Dissertation_Lydia Komini

MASTER THESIS
MSc. International Transport
BST302
The emergence of short-term contracts in the
LNG trade and the implications for
LNG shipping
By
Lydia Komini
Student number: 1448539
11.09.2015

ii
Abstract
The natural gas has turned within the last decades in a major fossil fuel, together with oil and coal.
Its insignificant environmental footprint has been acknowledged worldwide and the number of
countries participating in its trade has also soared. The advantages of Liquefied Natural Gas
(LNG), which refer in particular to costs and ease of access, via specified vessels has also acquired
a significant percentage of the global natural gas trade.
Since its emergence, the LNG market has been tied up with bilateral long-term contracts of 20 or
25 years between specific sellers/producers and importers that were written before the initiation
of the construction process. The contracts signed are known as sales and purchase agreements
(SPA). However, as the market changes, mainly due to the entrance of new players in the market,
the need for internationalising the LNG market has augmented. Thus, contracts of a shorter time
horizon have arisen and spot trade is also making its first steps.
LNG shipping, a core leg of the LNG supply chain, has also been transformed within the last
decade and is projected to change further, as spot trade and speculative orders of LNG vessels
increase. In this thesis there has been an attempt to discuss the “new era” for the LNG shipping
and the members involved. The discussion that takes place in the last chapter of this paper analyses
these changes and the author forecasts how the growth of spot trade will influence LNG shipping.
It seems that charterparty forms, as well as routeing and scheduling and the sales and purchase
market will be the segments of the shipping market that will experience the largest changes within
the following years. Additionally, it is estimated that the fear of future tonnage surplus will hinder
the constant increase of the spot trade and. It is common consensus, though, that many years will
have to pass until LNG market becomes volatile enough to be compared with the amount of oil
traded on the spot trade.

iii
Acknowledgments
I am especially grateful to my supervisor, Dr. Jane Haider, for her helpful comments and
suggestions for the successful completion of this dissertation.
I would also like to thank my brother who first introduced me into the LNG world and imparted
his passion and useful knowledge on the sector.
Most and foremost, I would like to express my gratitude to my parents who supported me in all
aspects during the last year and Bruna that always made me smile even at the hardest moments of
this master degree.

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Table of Contents
Chapter 1: Introduction 1
1.1. Background of the research ............................................................................................. 1
1.2. Purpose, Aims and Objectives of the Research ............................................................... 3
1.3. Overview of the Methodology......................................................................................... 4
1.4. Structure........................................................................................................................... 4
Chapter 2: The LNG Market 5
2.1. The LNG Value Chain..................................................................................................... 5
2.2. Geographical markets ...................................................................................................... 7
2.3. Major players ................................................................................................................... 8
2.4. Supply of natural gas ..................................................................................................... 10
2.5. Demand for natural gas.................................................................................................. 13
2.6. LNG Infrastructure ........................................................................................................ 14
2.7. LNG fleet ....................................................................................................................... 16
Chapter 3: Contracting in the LNG market 21
3.1. Long-term contracts....................................................................................................... 21
3.2. The arise of short-term contracts and spot trade............................................................ 24
3.3. LNG contracts currently in force ................................................................................... 28
Chapter 4: Transformations in LNG Shipping 34
4.1. New Types of Charterparties ......................................................................................... 34
4.2. Vessel Routing and Scheduling ..................................................................................... 39
4.3. The development of the second-hand market ................................................................ 42
4.4. Other Implications ......................................................................................................... 44
Chapter 5: Summary and Conclusions 46
References 49

v
List of Tables
Table 1: Evolving LNG market structure 9
Table 2: Key factors for the emergence of spot and short-term trade 27
Table 3: Contracts concluded in 2014 30
Table 4: Brief comparison of available charterparties 39
List of Figures
Figure 1: Annual Growth in Energy Demand by Source 2
Figure 2: The LNG Value Chain 5
Figure 3: Major LNG Trade Movements in 2014 8
Figure 4: Distribution of LNG carrier ownership 10
Figure 5: Natural gas production from 1971 to 2013 by region (in bcm) 11
Figure 6: 2014 LNG exports by country 12
Figure 7: 2014 LNG imports by country 14
Figure 8: Historical and Projected number of LNG export and import plants 16
Figure 9: LNG Carrier types Sources 17
Figure 10: LNG Orderbook Development 18
Figure 11: Average LNG Newbuilding prices 19
Figure 12: Estimated Short-term Future Conventional Vessel Deliveries 20

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Abbreviations
bcfd billion cubic feet per day
bcm billion cubic metres
COA Contract of Affreightment
cum cubic metres
EIA U.S. Energy Information Association
FLNG Floating Liquefied Natural Gas
FSRU Floating Storage and Regasification Unit
GIINGL International Group of Liquefied Natural Gas Importers
IEA International Energy Agency
IGU International Gas Union
LNG Liquefied Natural Gas
mcm Million cubic metres
mmtpa million metric ton per annum
mt million tonnes
mtpa metric tonne per annum
p.a. per annum
SPA Sales and Purchase Agreement
tcf trillion cubic feet

1
Chapter 1:
Introduction
1.1. Background of the research
Natural gas is one of the major fossil fuels, together with oil and coal, that prevails in the energy
market trade and is often quoted as the “successor of oil” (Gkonis and Psaraftis 2009, p. 228).
Total (2015) estimates that by 2035 natural gas will represent 25% of the world energy supply, of
which 13% is expected to be transported in liquefied form (LNG). Natural gas is mainly
transported from producing countries to importers via pipelines over thousands of miles and major
capital-intensive and inflexible projects are required to support this transport. Given that pipelines
have to traverse a lot of countries to reach their destination, there are often political or geological
barriers arising that render pipeline infrastructure inefficient and unfeasible. Additionally, the need
for internationalising natural gas trade and other external factors that that will be discussed in the
following chapters have led to the radical alteration of the market. Thus, the volume of LNG
shipped in specialised vessels has grown exponentially since the 1990s and the market is changing
rapidly, although the largest amount of natural gas is still transported via pipelines. More
specifically, within 25 years LNG trade volume has expanded from almost 50 mtpa in 1990 to
more than 200 mtpa in 2014 (IGU 2015). In the following figure the soaring development of LNG
trade during the period 1990-2013, compared to pipeline trade is obvious; LNG trade has grown
in almost a threefold pace than total natural gas consumption and by 38% faster than the traded
pipeline volume (Clarkson Research Services 2014a).

2
Figure 1: Annual Growth in Energy Demand by Source
Source: (Clarkson Research Services 2014a)
Simultaneously, the number of trading countries has been increased within the same period; by
the end of 2014 the number of exporting countries reached nineteen (Clarkson Research Services
2014b) and between 2008 and 2013 eleven new countries entered the market and started importing
LNG (IGU 2015).
Traditionally, the natural gas trade has been tied up with bilateral long-term contracts of 20 or 25
years between trading partners that are written before the initiation of the construction process. As
far as the LNG trade is concerned, the most critical investments concern the exploration,
production, liquefaction and regasification processes. Consequently, given the infrastructure
specificity and the requirement for such large investments, a significant risk from both the
supplier’s and buyer’s side is implied; the exporter bears the upstream investment risk, whereas
the importer has to face the energy supply risk. These risks have been leveraged by the conclusion
of long-term sales and purchase agreements (SPA).
It has been noted, though, that during the past decade, stakeholders of the LNG market are
increasingly and rapidly moving towards trading under short-term contracts or on the spot market,
whereas more flexible long-term arrangements are also emerging and average contract duration is
decreasing. Nevertheless, there is no doubt that long-term contracts are still driving the market. At
this point it should be underlined that since it is very common in the literature and reports from
6.8%
5.0%
2.4%
1.2%
0%
1%
2%
3%
4%
5%
6%
7%
8%
LNG Trade Pipeline Trade Natural Gas
Consumption
Oil Consumption
Annual Growth in Energy Demand by
Source 1990-2013

3
organisations, such as the IEA and the US EIA, to use the terms spot-trading and short-term market
interchangeably, the same pattern will be followed in the current paper.
It has been precisely this change and the increasing importance of LNG in world economy and
energy supply that attracted the author’s interest and determined the topic of this dissertation.
1.2. Purpose, Aims and Objectives of the Research
Traditional contracting patterns in the natural gas and LNG market have been thoroughly
discussed in the literature and analysed as to how they have formed the trade internationally.
Similarly, a multitude of studies have been undertaken on the emergence of spot market and short-
term contracts. Nevertheless, the vast majority of previous papers has focused on the drivers of
this radical market shift, the consequences on LNG pricing sold on spot at major hubs (e.g. Henry
Hub in the US) and arbitrage opportunities. To the author’s knowledge there has not been any
previous paper that studies the implications of new contracting patterns exclusively on shipping
on a cohesive and analytical way. Thus, the scope of this dissertation is to cover this gap in the
LNG literature.
The aim of this paper is to answer the following research question:
 How and to what extent will short-term contracts and spot trade influence the shipping
stage of the LNG value chain?
In other words, the dissertation mainly aims at analysing the effects and the implications of short-
term contracting in LNG shipping. For this reason, a discussion of the historical evolution of long-
term contracts is deemed necessary to help the reader understand the background of the market
and realise why these contracts have prevailed in the LNG market until recently. In the following
sections it will be clarified that it has been primarily the asset specificity of LNG investments that
determined the duration and strict terms of LNG contracts. However, as LNG trade enters slowly
its mature period and takes place in an international basis, changes in demand and external
environment require stakeholders to contract differently. Thus, spot market has emerged and
signified the beginning of a new era for LNG trade, for the parties involved and for every segment
of the LNG value chain, particularly the shipping leg. The purpose of this paper is to trace the
significance of this alteration in the market, as well as to find and discuss the direct or indirect

4
consequences for LNG vessels shipowners and charterers. The author will seek to discuss some
of the challenges that have already arisen for LNG shipowners that do business under the new
market trends, as well as forecast some implications that will change LNG shipping radically, if a
strong spot market is established. The findings will not only focus on the operational challenges
for LNG shipowners, but also on the new contractual environment between shipowners and
charterers.
1.3. Overview of the Methodology
Given the high illiquidity of the LNG market and the author’s restricted access to databases and
quantitative reports, this paper will be exclusively based on secondary data. This data will be found
in government reports and publications from internationally acknowledged companies and
organisations, such as BG Group, BP, US Energy Information Administration (EIA), International
Group of Liquefied Natural Gas Importers (GIINGL) and International Gas Union (IGU), as well
as Clarksons Research database and Lloyd’s List.
1.4. Structure
The dissertation consists of five chapters. Firstly, we present the natural gas and LNG industry,
the structure of LNG market and the current situation regarding production and consumption
volumes and the LNG fleet. In chapter 3, the literature review will focus on the historical evolution
of LNG long-term contracts. Following this, in chapter 4 there will be a long discussion regarding
the changes in the LNG environment which led the market towards contracting on the short-term
and on the spot and pinpoint the importance of this phenomenon on the LNG trade. The
implications of the new contracting pattern on LNG shipping will be analysed in depth in chapter
4. Finally, conclusion remarks and propositions for further research are provided in the last section
of the paper.

5
Chapter 2:
The LNG Market
2.1. The LNG Value Chain
The major mode of transport for natural gas is a pipeline grid. Research has shown, though, that
transferring natural gas in liquid form is more practical where markets cannot be served by
pipelines (stranded gas reserves) and for distances longer than 2,500 km, LNG is more cost-
effective per cum transported (Jensen 2009). In other words, LNG is more competitive on long
distances.
LNG is natural gas, predominantly composed of methane, that has been chilled in very low
temperatures (-163°C), purified and converted to liquid in specially built refrigeration units, called
“trains”. The principal advantage of LNG lies on its shrinkage of volume to less than 1/600th of
its gaseous form that allows for greater efficiency in storage and transport.
Figure 2: The LNG Value Chain
Source: (Total 2012)

6
The natural gas process chain consists of five separate but linked stages, as shown in Figure 2, and
is divided in three main streams:
 the upstream which includes the extraction of natural gas, its treatment and distribution
via pipelines to liquefaction plants, where gas is converted to liquid and stored,
 the midstream which involves the loading of LNG on specialised LNG tankers and onward
transportation1
and
 the downstream where LNG is regasified in import terminals and stored temporarily 2
.
Liquefaction plants are often quoted as colossal refrigerators and reflect the largest investment of
the supply chain. At this point, after natural gas is liquefied it is then stored until it is loaded on a
vessel, truck or train.
When the specially designed ship reaches the plant, loading of LNG begins, under FOB, ex-ship
or CIF terms. Traditionally, LNG vessels had been built for dedicated projects and suppliers and
served specific markets, according to the clauses of the long-term arrangement. Besides the
practical importance of the shipping process, it is significant to bear in mind that if the increase in
shipping capacity does not follow the rhythm of liquefaction or regasification capacity, then in the
long-run it may indicate a potential bottleneck in the LNG chain, as happens with the pipeline
network (Lochner 2011). For instance, the lack of LNG vessels may create the so-called
scheduling and routeing problem and hamper the efficiency and coordination of other segments in
the chain (Dorigoni et al. 2009). On the other hand, if LNG shipping tonnage exceeds the produced
or demanded amount of LNG, then overcapacity emerges. Kavalov et al. (2009) clarify that
shipping is the most volatile part of the LNG supply chain, as a potential buyer of LNG may turn
to other suppliers or even other energy sources in case LNG is not transported in an effective and
cost-competitive way.
In the last part of the value chain LNG cargoes are discharged at the import terminal of the buyer’s
country and then distributed via a pipeline grid to end users.
1
However, LNG can also be transported by tank truck and, occasionally by rail as happens in Sweden and Finland,
where the necessary infrastructure and rail gauges are available (Ragnar, M. 2014. Rail Transportation of Liquid
Methane in Sweden and Finland. SGC.
2
Alternatively, LNG can be delivered to offshore terminals for storage and regasification (Floating Storage and
Regasification Unit-FSRU), or, if no storage is needed, to Floating Regasification Units (FRU).

7
The cost breakdown of the supply chain depends highly on the plant (Durr et al. 2005), but a
general idea of the cost allocation is proposed by Wang and Notteboom (2011):
 Field production: 15-20%
 Liquefaction plant: 30-45%
 Shipping: 10-30%
 Regasification: 15-25%
Although the industry has witnessed a significant decrease in individual costs of the value chain,
the liquefaction process continues to represent the most expensive part of the chain.
2.2. Geographical markets
The trade of LNG takes place in three different geographical regions; the two major markets
include the Pacific and the Atlantic Basin and Middle East is the intermediate. The Asia/Pacific
market is the largest importing market. Historically, Japan and South Korea represent the leading
importers in the Pacific region and in 2014 these two countries imported 120.6 bcm and 51.1 bcm,
respectively, representing 70 percent of total LNG imports in the region (BP 2015b). It is
predicted, though, that by 2035 China will be the second largest importer after Japan (BP 2015a).
The major exporting countries in the Asia/Pacific market are Australia, Malaysia and Indonesia.
In the Atlantic basin, LNG is mainly moved towards South and Central America and Europe,
whereas shale gas revolution is expected to change US profile to a net exporter (EIA 2015). More
specifically, Mexico, Spain and the UK in 2014 imported in total 36.1 bcm out of 85.1 bcm
transported in the area. Nigeria is the largest exporter in the Atlantic basin.
The Middle East market, particularly Qatar, is the main supplier for the other two markets,
balancing supply and demand in the global LNG trade (Clarkson Research Services 2014a).
The imports and exports trends discussed above can be observed in Figure 3.

8
Figure 3: Major LNG Trade Movements in 2014
Source: (IGU 2015)
2.3. Major players
As it shown in the following table, traditionally, private and national energy companies used to
control the lion’s share of the LNG supply chain, from production, liquefaction and shipping to
final distribution to end consumers. In other words, the market had an oligopolistic structure and
was in the hands of a few companies. However, as countries sought to improve their energy
security (e.g. European states aimed at reducing dependence on Russian natural gas supply via
pipelines), deregulation and liberalisation of upstream and downstream gas markets alike started
taking place globally. Thus, independent shipowners emerged, together with cooperation
agreements and consortia among market players. It appears, also, that the desire of some major
companies to focus on their core business (i.e. LNG production, liquefaction and regasification)
explains the increasing ownership of the world LNG fleet by independent shipowners.

9
Table 1: Evolving LNG market structure
Nowadays, we see independent shipowners cooperating closely with upstream sellers and shipping
companies being involved in the regasification process with FSRUs. For instance, in 2014 MOL
decided a deal on joint ownership with Japanese Chubu Electric Power Company of a new vessel
for the transfer of LNG from Australian to Japan, whereas Hoegh LNG is established as an owner
and operator of floating LNG import terminals. Although competitiveness is now stronger in the
market, state monopolies, especially in the Middle East, continue to dominate. State-owned Qatar
Gas is the largest LNG producing company in the world and holds the largest LNG fleet globally
(29 vessels) (Figure 4). Among the top 12 shipowners, Teekay, NYK, MOL, GasLog, K-Line,
BW and Angelicoussis Groups are independent shipowners, whereas Nigeria LNG Ltd. is by 49
percent controlled by the Nigerian government.
LNG VALUE CHAIN Traditional 1990’s Today - Future
UPSTREAM
Gas Production
State-owned or
international oil and
gas company
State-owned or
gas company
State-owned or
gas company
Pipeline
Joint Venture by
various market
participants
Liquefaction
Plant
Joint Venture by
various market
participants
LNG Shipping
Shipping company /
Buyer’s/Seller’s
minority interest
Shipping company,
Gas marketing
companies,
Upstream seller,
Downstream buyers
DOWNSTREAM
Regasification
plant
State-
owned/Regulated
gas (pipeline) or
electric company
State-
owned/Regulated
gas (pipeline) or
electric
company/Gas
marketing company
Gas marketing
companies, Stand-
alone tolling
companies, Pipeline
companies
Pipeline
Open access
regulated pipelines
Distribution
System
Regulated gas
distribution
companies
Source: Own representation based on Engelen and Dullaert (2010)

10
Figure 4: Distribution of LNG carrier ownership
Source: author’s representation based on Clarkson Research Services (2015a)
2.4. Supply of natural gas
Natural gas production is expected to increase dramatically in the next years. According to BP
projections (BP 2015b, a), total gas production will expand by 46.03 percent, reaching 5,069 bcm
by 2035 from 3,471.30 bcm in 2014 (BP 2015b, a). Within the last 40 years, the regional share of
natural gas production has been restructured, as OECD members’ share has halved from 71.3
percent to 35.5 percent because particularly Middle Eastern and Asian (excluding China)
production has soared (IEA 2014) (Figure 5). In 2014 out of 3460.6 bcm total natural gas produced,
only 997.2 bcm entered the international trade in either gaseous or liquid form (BP 2015b). It
seems that although natural gas trade will grow, demand will be mostly covered by indigenous
production, which is expected to reach 75 percent of world natural gas needs (ExxonMobil 2015).
However, Russian gas production will be most likely exported, increasing current exports by
approximately 25 bcfd (ExxonMobil 2015).
Others
47%
K-Line
3%
Angelicoussis Group
3%
Nigeria LNG Ltd.
3%
Shell
3%
BW Group
3%
GasLog
4%
MOL
5%
NYK
5%
Golar LNG
5%
Petronas
6%
Teekay
Corporation
6%
Qatar Gas
(Nakilat)
7%

11
Figure 5: Natural gas production from 1971 to 2013 by region (in bcm)
Source: (IEA 2014)
As far as the world proven natural gas reserves are concerned, at end-2014 they grew by 0.3
percent compared to end-2013 and stood at 187.1 tcm. The largest share is held by Middle East
(42.7 percent), followed by Europe and Eurasia (31 percent), with the former having the largest
reserves-to-production ratio (BP 2015b).
In 2014 the largest exporters of pipeline gas were Russia, Norway, Canada, Netherlands and the
US. In the LNG trade two new countries entered the market, adding to previous year’s seventeen
exporters. Qatar remained the pre-eminent LNG exporter, since it represented 31 percent of global
LNG trade, ie. 103.4 bcm (BP 2015b). Malaysia, Australia and Nigeria held the next three
positions in LNG exports and exported in total 90.8 bcm (BP 2015b). It is projected, though, that
by 2035 Australia will lead the market with 24 percent share of the market and overtake Qatari
LNG exports (BP 2015a).

12
Figure 6: 2014 LNG exports by country
Source: author’s representation based on IGU (2015)
The shale gas revolution in North America is expected to break the rules of the game for LNG
trade and transform US from a traditional importer of natural gas to an exporter by 2017 (EIA
2015). To put it simply, shale gas is natural gas trapped tightly between layers of shale formations
and whose extraction had been considered too costly or difficult to access until recently, in
contrast with conventional natural gas that is much easier to access, as rock formations, once
drilled, allow the gas to flow freely. However, as the supplies of conventional gas have started
declining and advancements in technology allow for more efficient and affordable methods of
drilling, production of shale gas has been escalated. According to EIA’s report (2014), US natural
gas gross imports will remain on the downward swing of the last eight years (since 2007) through
2040, whereas gross exports are expected to increase over the period. Shale gas production in 2040
will vary between approximately 18 and 35 tcf, depending on the oil prices and US natural gas
reserves, and natural gas exports will grow, partially due to significant LNG exports that will reach
3.3 tcf by 2040. ExxonMobil (2015) estimates that by 2040 LNG exports from North America
could significantly threaten respective Asian exports. The implications in the near future for LNG
trade will be tremendous, as geographically North America can serve both Asia and Europe and
Suez Canal expansion will offer the opportunity to US LNG vessels to haul cargoes to Asia faster
and with less bunker costs. It will also be interesting to see how Qatari and Australian exports will
0
20
40
60
80
Qatar
Malaysia
Australia
Nigeria
Indonesia
Trinidad&Tobago
Algeria
Russia
Oman
Yemen
Brunei
UAE
Peru
Eq.Guinea
Norway
PNG
Angola
Egypt
US
mtpa

13
be influenced by the emergence of the new competitor and whether future increase in demand of
LNG will be suffice to balance with the added supply.
2.5. Demand for natural gas
The global increase in energy demand, together with the quest for more environmentally friendly
energy supplies is, without doubt, good news for natural gas. Consequently, all international
projections show a dramatic increase in the future demand. There will be a 65 percent increase in
gas demand driven by both the end-use sectors (residential/commercial, transportation, industrial)
and power generation, but it seems that transportation will lead this rise, as the average annual
increase from 2010 to 2040 is at 7.2 percent, whereas the other sectors will grow by less than 2
percent p.a. within the same period (ExxonMobil 2015). BP (2015a) forecasts global demand for
natural gas to rise 1.9 percent p.a. and reach 490 bcfd by 2035. It seems that the Asia/Pacific region
will overtake European imports before the end of the decade and in twenty years it will represent
almost 50 percent of global net imports (BP 2015a), as more than 50 percent of natural gas
consumed in the area will be imported and local demand will increase by more than 100 bcfd
(ExxonMobil 2015). Demand in North America is expected to rise by more than 40 percent by
2040, and, in a large extent, will be covered by local production (EIA 2014). On the other hand,
increase of local demand in Africa and Latin America by 20 percent and 10 percent, respectively,
will be met by LNG imports (ExxonMobil 2015).
The major pipeline gas imports during 2014 were destined to Germany and US, which imported
85 bcm and 74.6 bcm, respectively. Significant volumes of pipeline gas were also transmitted to
Italy, Turkey and the UK. China currently represents 54 percent of imported pipeline gas in the
Asia/Pacific region (BP 2015b) and the total imported volume is expected to rise after the
completion of “Power of Siberia-2” project3
that will transfer gas from Russia to China via a
pipeline system.
As it has been discussed earlier and showed in the following figure, Japan in 2014 sustained its
leading position in LNG imports (120.6 bcm) throughout 29 countries that imported LNG in the
same year, holding 36.9 percent of global LNG imports (IGU 2015). However, the recent re-
3
An agreement of strategic co-operation signed between Russian Gazprom and China National Petroleum
Corporation (CNPC) in 2004, for the delivery of 30 bcm from Russia to China by Gazprom via a pipeline system.
The first supplies are expected to be transmitted in late 2015.

14
opening of the Japanese nuclear plants is expected to decrease significantly the amount of LNG
imported by the country. The importance of the Asia/Pacific region in LNG trade is obvious from
the fact that the three major importers belong within the Pacific basin. It also appears that these
countries will continue to play a determinant role, as it is projected that in 2040 80 percent of
future natural gas imports in Asia/Pacific will be covered by LNG cargoes (ExxonMobil 2015).
Figure 7: 2014 LNG imports by country
Source: author’s representation based on IGU (2015)
2.6. LNG Infrastructure
One of the main challenges in the LNG trade is to raise funds for the large-scale, billion dollars
infrastructure and to bridge the gap between demand and supply, i.e. if there is surplus of LNG
stored in liquefaction plants and/or low demand, then the seller and/or buyer is obliged to bear an
enormous capital risk due to the projects built but not effectively used. Thus, bilateral long-term
contracts prevailed to bind buyers to import a standard volume, which usually represents the
largest fraction of the liquefaction plant’s output, and to ensure supplier’s stable cash flows.
According to Tusiani and Shearer (2007), the complexity of required facilities and highly
specialised and experienced personnel, together with the limited number of players in the market
are the main reasons for the slow development of the LNG trade since the 1960’s.
0
20
40
60
80
100
mtpa
Other includes: includes Belgium, Canada, the Dominican Republic, Greece,
Israel, Lithuania, the Netherlands, Portugal, Puerto Rico, Thailand, the UAE
and the US

15
Besides the high capital costs that are linked to LNG projects, other factors that render their
completion very complex are political barriers, that, although significantly lower than pipeline
projects, have to be overpassed, as well as environmental and geographical aspects to be dealt
with. The meantime between the initial propositions over a new project and its delivery and
implementation may be more than four years. However, the surge in LNG demand during the last
decade has been followed by an exponential increase in the liquefaction trains and import terminals
alike.
According to GIINGL’s (2015) data, in 2014 there were 108 operational liquefaction trains in the
world with a combined nominal liquefaction capacity equal to 298 btpa. The majority of these
projects are owned by various state-owned and private companies and all are operated by a single
organisation. PNG LNG site came online in May 2014, making Papua Nea Guinea the 20th LNG
exporting country.
In the opposite side of the LNG value chain, existing LNG import projects have been expanded
with new trains or new plants have been built. Last year six new regasification terminals of total
20 mtpa have been added to the global receiving capacity, which currently stands at 53 mcm
(GIINGL 2015).
The following figure shows the escalation in the number of liquefaction and regasification plants
within the last twenty five years, as well as the projection for the near future. It is obvious that
until 2015 regasification plants are increasing in a faster pace than liquefaction projects, but it
seems that in the next five years this trend will be reversed.
The LNG infrastructure has observed a significant change the last years, since new floating
technologies in liquefaction and regasification processes have emerged. Floating liquefaction
plants (FLNG) are actually offshore LNG production vessels where natural gas is converted to
liquid, as it would in a traditional coastal plant. Their main advantages are that they need shorter
time to be delivered to market than onshore alternatives, they are mobile and allow operators to
gain easier access to stranded gas reserves, although the costs of building such units remains high
(Larson 2009; Wood 2012). Prelude FLNG, constructed by Shell, is the world’s largest floating
offshore facility with a storage capacity of 220,000 cum that is built to liquefy gas in the waters
of Australia (Shell 2015).

16
Figure 8: Historical and Projected number of LNG export and import plants
Source: (BP 2013)
Similar major FLNG projects are under construction all over the world, mainly in Australia,
Malaysia and Colombia (IGU 2015). Other technological innovations related to LNG
infrastructure, refer to onboard regasification (the LNG fleet currently numbers nineteen
regasification vessels (Clarkson Research Services 2015a)) and Floating Storage and
Regasification Units (FSRU) (Wood 2012).
2.7. LNG fleet
Generally, the LNG shipping sector is characterised by high entry barriers and this explains,
partially, the ownership structure of the past years. These barriers refer mainly to the high costs of
building an LNG vessel, the need for experience and high technological requirements from the
side of shipyards, charterers and financiers and the illiquidity that prevails in the secondhand
market (Stopford 2009). Nevertheless, within the last decade the face of LNG fleet has changed
drastically; new ship operators have entered the market, vessel size has grown more than six-fold
and technology has seen some unthinkable improvements.
#ofprojects

17
The first LNG cargo was transported in 1959 by “Methane Pioneer” (5,000 cum) in a trip from US
to the UK, whereas the first purpose-built LNG vessel was “Methane Progress” (27,400 cum) that
served the Algeria-to-Canvey-island LNG trade for 22 years. Modern LNG vessels are double
hulled and as illustrated in Figure XXX there are two main designs of LNG tanks, the moss sphere
and the membrane design, each of them having a different supporting system. Today, the majority
of existing LNG ships carry LNG in spherical tanks (Figure 9a) (IGU 2015).
(a) Moss sphere cargo design (b) Membrane design
Sources: (BG Group 2012; BP 2014)
Regarding the size of new vessels, this has been increased to exploit economies of scale and recent
orders show that the average cargo capacity varies from 150 to 180,000 cum. Qatar Gas has been
the first and only company so far that ordered in 2007 32 tankers of two new classes; Q-flex and
Q-Max. The capacity of the former is 210-217,000 cum and of the latter is 260-270,000 cum. Due
to their high inflexibility and incompatibility with many of the world’s LNG terminals, these
vessels were built to serve exclusively new projects in Qatar (QatarGas 2015).
The orderbook of LNG ships can be divided between two periods; the pro-1990’s and the post-
1990’s. During the 1980’s a significant decrease of demand for LNG coupled with the surge in
energy prices, limited the plans for new LNG projects and, consequently, shrunk the orderbook.
At the rise of the new decade, though, the interest for both new projects and vessels increased and
that led to growth of new orders. The period from 2003 to 2008 was characterised by consecutive
orders, which only in 2007 numbered 140 new shipbuilding contracts of a combined 23 mcm
capacity. However, the global recession in 2009 led to a sharp fall of orders by 83 percent in 2011
Figure 9: LNG Carrier types

18
compared to 2008 and the delivery of vessels ordered in the previous years resulted in a tight
market (i.e. oversupply). Slowly by 2012 the orderbook started recovering and until July 2015 157
new orders had been placed. The aforementioned trends are shown in the following figure.
Figure 10: LNG Orderbook Development
Source: author’s representation based on data from Clarkson Research Services (2015a)
Particularly the years when the orderbook capacity overpassed existing fleet are worth mentioning.
Currently the total LNG fleet comprises 428 vessels of 60 mcm total capacity (Clarkson Research
Services 2015a) and in 2014, the average size of delivered vessels was 161,000 cum (IGU 2015).
Whereas the LNG industry is a highly capital-intensive market, costs in all components of the
value chain have decreased during the last twenty years. Construction costs of LNG vessels depend
on the costs of insulated tanks, price of steel and number of available shipyards at the given time,
size of the vessel and of course the balance between demand and supply of LNG at the date of the
newbuild contract. The increase in tankers’ cargo capacity has created significant economies of
scale that have driven per-unit LNG shipping costs downwards, although the limited flexibility of
these vessels due to facilities’ capacity restrictions should be taken into account. The average
prices of newbuilt contracts are illustrated in the following diagram, where we can see that before
the crisis in 2008, the increasing cost of steel and advancements in shipbuilding technology
between 2003 and 2008 rocketed up the prices for new vessels (Clarkson Research Services
2014a).
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
-
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
30,000,000
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015*
cum
*data as at the 7th August 2015
LNG Orderbook
LNG Orderbook as a % of the existing fleet

19
Figure 11: Average LNG Newbuilding prices
Source: author’s representation based on data from Clarkson Research Services (2015a)
A representative example from the newbuilding prices in 2015, refers to the purchase by MOL of
two 180,000 cum LNG carriers whose value slightly overpassed $200m each (Brown 2015b).
Given the fact that even today the orders of the vast majority of vessels are tied to the shipping
requirements of specific liquefaction projects that come online, it is obvious why the LNG
orderbook fluctuates according to the interest in such projects. Thus, the estimation made by IGU
(2015) that delays in the completion of projects in Australia and the US, may lead to an oversupply
of vessels ordered in the period 2012-2013, is logical.
As explained in the introduction, traditionally LNG tankers have been engaged in long time-
charters, which imply less revenues’ volatility for shipowners, and, thus, short-term fixtures or
voyage charters are very limited. In fact, as Wang and Notteboom (2011) mention, until 2011 there
was no LNG facility built without any pre-arranged and uncommitted liquefaction capacity.
However, as a fraction of the total capacity of liquefaction projects is nowadays not contracted to
particular importers and commodity traders have entered the LNG market, spot trade has arisen
and speculative tonnage built is taking place. Teekay, for instance, ordered speculatively two
vessels in 2012, although six months later finally time-chartered these newbuildings for five years
to Cheniere Marketing (The LNG Journal 2015). During 2014 eighteen tankers were ordered on a
speculative basis and in the first quarter of 2015 four of the newbuild contracts signed were not
tied to a particular project (IGU 2015). Since 2012 both average spot earnings and 1-Year time
charters are constantly decreasing, due to the ample tonnage open for charter, and at July 2015
were at 40,926 $/day and 69,846 $/day, respectively (Clarkson Research Services 2015). IGU
(2015) expects that in the next four years conventional vessel (161,000 cum) deliveries will be
125
150
175
200
225
250
275
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
millionUS$
LNG Carrier 147,000 cbm LNG Carrier 160,000 cbm

20
allocated as shown in figure 12, where we see that both speculative and specified orders decrease
slightly, although surplus capacity will not be absorbed at least before 2017.
Figure 12: Estimated Short-term Future Conventional Vessel Deliveries
Source: (IGU 2015)
20
33
26 23
11
10
9
8
0
10
20
30
40
50
2015 2016 2017 2018
#ofvessels
Term chartered Available for charter

21
Chapter 3:
Contracting in the LNG market
3.1. Long-term contracts
Long-term arrangements between LNG producers and importers have been the main characteristic
of the LNG market since its inception and have formed the LNG market as we know it today.
Generally, long-term contracts are contractual relationships formed between a seller and a buyer
that include significant financial and operational benefits and restrictions for the parties involved
and imply recurrent or occasional transactions.
The theoretical background behind long-term contracts, the circumstances under which they are
signed and the effects of contract provisions are thoroughly analysed by Williamson (1979, 1985),
in his theory of transaction cost economics. He considers long-term contracts as the intermediate
between short-term contracts and vertical integration (internal organisation) and underlines that
the uncertainty of demand and supply in transactions, transaction frequency within the relationship
and the degree of transaction-specific investments are the dimensions used for characterising
transactions. More specifically, growing specificity and uncertainty increase contract duration,
whereas intensified frequency of transactions leads to contract duration reduction. According to
Williamson, in cases of relationship-specific (idiosyncratic) investments, where vertical
integration is not an option, long-term contracts guarantee the minimisation of transaction costs
and serve as a means to mitigate the ex post hold-up problem4
or opportunistic behaviour of either
party.
This strategy of sellers’ seeking to secure their position before sanctioning a project through long-
term contracts has been long known in the energy sector and widely adopted by the market players.
Joskow (1985, 1988) is one of the first researchers to show empirically that in the U.S. coal
industry there is a strong correlation between the level of assets or investments specificity and the
4
“When a transaction entails one party committing capital that has little value for other uses, the other party has a
strong incentive to appropriate the rents arising from the relationship through opportunistic behavior. Anticipating
this risk, also called the “hold-up” problem, buyers and sellers sign long-term contracts” (Creti and Villeneuve
2005, p. 78).

22
contract duration. In a more recent paper, Saussier (1999) uses European data and by applying
Williamson’s transaction cost theory, confirms that longer contracts are formed in order to limit
transaction costs, whereas duration of the contract and the level of uncertainty are negatively
related.
As far as the natural gas and LNG trade are concerned, there is a long discussion in the institutional
economics literature regarding the duration of contracts written in the market. The gas industry,
since its emergence, has been fully based on long-period agreements between exporters and
trading companies, who control either the pipelines, where gas is transported in aerial form, or the
shipping leg, in cases where LNG vessels are used for the transportation of liquefied gas. For this
reason it is often quoted that the natural gas market had a clearly industrial profile. This trend has
been analysed thoroughly in the literature and it has been observed that such contracts between
exporters and importers of natural gas usually reach 20 or 25 years (Ehrman 2006; Engelen and
Dullaert 2010; Asche et al. 2013). Traditional contracts link specific buyers and sellers in an
inflexible pairing through Sales and Purchase Agreements (SPA), which serve to transfer future
LNG volume risk to buyers, whereas the price risk of LNG investments is borne by the producers
(Jensen 2003; Zhuravleva 2009; Ruester 2010).
One of the main reasons for this trend has been, and continues to be, the provision of assurance
for investors, who engage into the completion of capital intensive liquefaction projects, and the
security of supply for the buyers (Ruester and Neumann 2006). In other words, the specificity
mentioned by Williamson as a determinant factor of contracts’ duration is the key factor in the
natural gas industry; given the high site specificity of constructed pipelines for the transfer of
natural gas and of projects for the trade of LNG, it is comprehensible why long-term contracts
have prevailed in the industry. The significance of investments linked to specific infrastructures is
underlined by Hirschhausen and Neumann (2008) who conclude that high investment specificity
and increasing competitiveness in the natural gas market are positively and negatively related to
contract duration, respectively. For example, open access to pipelines from various competitors is
deemed as a decreasing factor of transaction costs and, thus, contract duration (Doane and Spulber
1994). Moreover, IEA (2014) stresses the importance of long-term contracts in securing full
utilisation of liquefaction plants, since all output capacity is tied to specific buyers and with terms
that importers cannot exonerate themselves from.
In addition to this, strong regulation in the US and European markets in the form of take-or-pay
provisions and destination restrictions, did not allow the natural gas or LNG trade to evolve in the

23
spot trade, as happened in the case of oil after the oil-crisis in 1973, that transformed the trade and
rendered it more transparent (Kavalov et al. 2009). Take-or-pay obligations committed importers
to either taking delivery or paying for all the contracted gas volume and not re-exporting it,
irrespective of fluctuation in demand at the time of cargo delivery. Simultaneously, besides these
off-take and destination rigidities, natural gas was indexed to oil prices and there was limited
flexibility in renegotiating price terms5
.
Canes and Norman (1984), as well as Masten and Crocker (1985), point out how the take-or-pay
clauses included in long-term contracts serve as mitigation tools to protect the parties from
contractual hazards, such as detrimental renegotiations and legal disputes, and suitable risk-
sharing mechanisms for the minimisation of opportunism. More specifically, Canes and Norman
(1984) underline the importance of take-or-pay restrictions of long-term contracts for the
maintenance of stable cash flows and, consequently, for the financing of large scale investments
with more debt. Building upon this theoretical approach, Hurtley (2013) creates a model to show
that natural gas long-term contracting minimises cash flow volatility, although it may lead to ex-
post inefficiency. Nevertheless, as underlined by Masten and Crocker (1985), this inefficiency
may be limited by take-or-pay clauses.
Following the deregulation of wellhead US natural gas prices in 1978 (Natural Gas Policy Act of
1978), Hubbard and Weiner (1986) develop a theoretical model on the importance of take-or-pay
provisions, by analysing 884 natural gas contracts between producers and pipelines; they find that
long-term agreements may arise in regulated or un-regulated markets where uncertainty prevails,
but deregulation may decrease significantly the duration of the contracts. Besides market
regulation, according to Neuhoff and Hirschhausen (2005), short-term and long-term demand
elasticities are concerned to be chief determinants of the contracting period; in cases where
demand elasticity in the near future is lower than the long-run elasticity, long-term arrangements
and their inherent provisions are chosen by both natural gas producers and buyers.
Ruester (2009) focuses exclusively on the LNG market and uses data from 261 international LNG
long-term supply contracts (between three and thirty years duration) that have been written since
the beginning of the industry in the 1960s until 2009, in order to examine the factors that determine
contract duration as they have been argued by Williamson. Ruester confirms the hypothesis of
transaction cost economics that LNG contracts duration expands as dedicated asset specificity
5
These clauses were known as “price indexation clauses”.

24
increases, since buyers that rely strongly on one supplier prefer to engage into long-term contracts,
even if that entails limitation of flexibility in terms of securing energy supply. On the other hand,
Ruester’s results show that higher environmental uncertainty that derives from political instability
is not statistically significant and has no impact on contract duration, in contrast with price
volatility that decreases the contract duration as the risk “of being bound by a long-term
commitment which no longer reflects the actual price level” increases (Ruester 2009, pp. 105-
106). The third variable that she uses refers to the transaction frequency within the relationships
in terms of cargo volumes and the transaction frequency between trading partners. She proves that
the duration of an LNG contract does not depend on the volume of LNG trade between the
contracting parties, but she confirms empirically the hypothesis that the frequency of transactions
affects significantly and in a positive way the duration of the contract.
3.2. The arise of short-term contracts and spot trade
During the last decade or so, natural gas market, and LNG trade in particular, is rapidly moving
towards a new generation of trading; long-term contracts which contain flexibility clauses have
emerged, together with contracts issued for shorter periods than of those in the past and spot trade
currently holds a significant part of LNG trade. Another change mentioned by Ruester (2010)
regarding changes in contracting patterns and organisational strategies, refers to the substitution
of ex-ship (DES) deliveries by free on board (FOB) deliveries, which imply lower shipping costs
for the buyer, and the increasing number of vertical integration and strategic partnerships between
buyers and suppliers for reasons that are thoroughly discussed by Ruester and Neumann (2006).
Regarding the European market, new long-term contracts have been written for eight to fifteen
years (Kavalov et al. 2009) and in the global trade there have been contracts of less than four years
(Hartley 2014). Flexibility in contracts, as stated by Hartley (2013) and Ruester (2010), is often
expressed in terms of adding quantity adjustments in the contract, relaxing SPAs’ imposed rigidity
of binding specific tankers to a particular import country and linking LNG prices to natural gas
prices in the spot market. The growth of the spot market in the LNG trade is considered as a
breakthrough, which will weaken monopolistic trends, enhance market liquidity and allocative
efficiency, reduce significantly the price of natural gas and offer arbitrage opportunities to
independent traders (Engelen and Dullaert 2010). However, Ritz (2014) Polina and Zhuravleva
(2009) present important limits that still prevail and hamper the growth of a global LNG arbitrage

25
market. Zhuravleva (2009) finds twelve barriers that do not allow LNG arbitrage to develop and
categorises them under four groups: core barriers, barriers requiring greater trading skills, barriers
specific to companies, cargoes and locations and transaction cost barriers. For both papers,
extended committed capacity, illiquidity of the LNG market and contractual and technical
restrictions seem to be the main factors preventing LNG arbitrage from growing. It is obvious that
all these limitations derive from the fact that the majority of LNG is still traded under long-term
arrangements.
The drivers that have led to this shift in the market vary. In table 1 IGU (2015) underlines the key
factors that led to the development of shorter contracting practices in the recent years. Firstly,
demand for LNG is constantly increasing, mainly due to the turn of countries to fossil fuels with
smaller environmental footprint (Engelen and Dullaert 2010; EIA 2014), and its emergence as a
fuel (IEA 2014; IGU 2014), its lower cost for medium and long-term distances, compared with
pipeline gas (Dorigoni et al. 2009; Wang and Notteboom 2011) and its easier access to stranded
gas reserves (Ajay and Opasanya 2007; Dorigoni et al. 2009; Engelen and Dullaert 2010). In
addition to this, the influx of independent LNG vessel owners in the last decade have rendered the
market more competitive, whereas costs for each stage of the LNG value chain are declining.
Similarly, the global growth of LNG demand, and, thus, the need for more vessels, not attached to
long-term contracts, free to match uncommitted liquefaction capacity, has led to speculative
ordering of LNG tankers to be employed in the spot market (Dorigoni et al. 2009). All the
aforementioned trends have been discussed in the previous section. Therefore, contracting under
short-term agreements or on the spot market is more common nowadays.
Athanasopoulos (2006) in his discussion about the emergence of short-term trade, presents the
market as a reinforcing loop, where internal factors interacted and led inevitably to the growth of
spot-term trading. In more detail, Mazighi (2004) refers to external natural, economic,
transportation and institutional conditions that contributed to the evolution of short-term market
within time.
The LNG market was developed within a strictly regulated environment, where the price of gas
was determined at the export’s wellhead, whereas the volume of imported gas had first to be
audited and approved by the government, before its distribution to end users. The main
consequence of this strong regulation was the creation of rigid monopolies and consequent high
prices for consumers (Tusiani and Shearer 2007). A new era for LNG started in the late 1970’s,
when US and Canada pioneered and liberalised the LNG market, followed by the UK and more

26
recently by the European Union. As a result, gas trading hubs arose that increased competitiveness
and allowed LNG prices to be defined more transparently. Deregulation of the market has been
reflected, for instance, by the possibility offered to third parties to acquire open access along the
facilities of the LNG chain, thus allowing independent corporate entities to emerge and negotiate
contract terms and LNG at spot prices. Similarly, the characterisation of destination clauses as
anti-competitive from the EU and their gradual elimination from long-term contracts supported
the growth of the spot market, given that LNG cargoes, theretofore impossible to be transported
outside importer’s national borders, could be re-exported where a price advantage was exploitable
(Nakamura 2009).
Other factors that forced the market towards the spot trade are mentioned by Brito and Hartley
(2007) who indicate that increasing seasonal variations in demand have to be covered by the spot
market. Additionally, oversupply in liquefaction capacity (Aune et al. 2009) and technological
advances in liquefaction plants which increased their potential production (Engelen and Dullaert
2010), cannot be fully covered by long-term contracts and support the development of the spot
trade.
Literature underlines the positive results of short-term contracts and spot trade on the LNG
shipping market, such as the growth of cross shipping and ensuing decrease of transport costs for
shipping operators (Dorigoni et al. 2009; Kavalov et al. 2009) and the more efficient utilisation of
vessels (Engelen and Dullaert 2010). These consequences will be analysed thoroughly in the next
chapter. On the other hand, limited security against possible fluctuations of spot prices are taken
into account in the analysis of the disadvantages of spot trade for gas importers (Engelen and
Dullaert 2010; Hartley 2013). Although not widely used, as extensively as in the case of the oil
trade, hedging instruments are gaining ground in order to protect parties from such risks.
The reasons mentioned above are well summarised in Table 2.

27
Table 2: Key factors for the emergence of spot and short-term trade
Source: (IGU 2015)
Nonetheless, a crucial question that arises is where the flexible volume to be traded under the
short-market derives from, given that the lion’s share of liquefaction plants’ capacity is
“committed” to specific buyers. Firstly, during the ramp-up period, the liquefaction plant is already
built and LNG can be produced and exported, but the buyer is provided with some time to “warm
up” the demand side and has the possibility to accept less volumes than the ones agreed in the
contract. In the meantime the producer can benefit from this time-mismatch in supply and demand
by selling these wedged volumes of LNG in the spot market. Tusiani and Shearer (2007) underline
that with the increase in liquefaction trains and production, this ramp-up period has been extended,
allowing producers to achieve even higher spot sales. Another source of surplus capacity emerge
from the expiration of long-term contracts which are not re-newed or re-negotiated. The increased
competitiveness among plants for the market, the influx of new buyers and the relaxation of
regulation encourages exporters to sustain a higher percentage of the produced capacity in the spot
market. Export terminals that have already been financed by the original agreement can be
disengaged from entering into new long-term contracts and their volume can be forwarded to the
The growth in LNG contracts with destination flexibility, chiefly from the Atlantic basin and Qatar,
which has facilitated diversions to higher priced markets.
The increase in the number of exporters and importers, which has amplified the complexity of the
trade and introduced new permutations and linkages between buyers and sellers.
The lack of domestic production or pipeline imports in Japan, South Korea and Taiwan, which pushed
these countries and others to rely on the spot market to cope with any sudden changes in demand, like
the Fukushima crisis.
The surge in global regasification capacity; in 2000 global receiving terminal capacity was 280 mtpa,
whereas by the end of 2014 regasification capacity reached 710 mtpa.
The large increase in demand in Asia and in emerging markets, such as Southeast Asia and Latin
America, which accelerated tightness in the LNG market.
The decline in competitiveness of LNG relative to coal (mainly in Europe) and shale gas (North
America) that has freed up volumes to be re-directed elsewhere.
The large disparity between prices in different basins, which made arbitrage an important and lucrative
monetisation strategy.
The large growth in the LNG fleet, which has allowed the industry to sustain the long-haul parts of the
spot market (chiefly the trade from the Atlantic to the Pacific).

28
spot market or written under short-term contracts, the duration of which will be determined by the
period of the loan payout (Jensen 2004). Additionally, the over-commitment of buyer, the
conservative liquefaction plant design, contract and operational flexibility or contract failure are
other factors that LNG over-capacity may derive from and enhance spot trade (Tusiani and Shearer
2007).
3.3. LNG contracts currently in force
During last year 69 percent of global LNG was traded under long-term contracts and from the
241.1 mt transported, 74.7 mt were in the spot and short-term market6
, a 7 percent increase from
2013 (IGU 2015). By the end of 2014 there were in total 209 long-term contracts7
with an average
nominal capacity of 1.36 mtpa and the majority of them were under DES terms. Their average
duration period was 20 years, which reflects the tendency of market-players to lock-in fixed
agreements and verifies the research mentioned above. Some of these contracts should be
highlighted:
 Algerian government-owned Sonatrach has the oldest long-term contractual agreements
with GDF Suez that were first signed in 1972 and 1973 and both expire in 2019.
 There are three long-term contracts that have no expiration date, i.e. the duration of the
contract expires at the depletion of the reserves. These are contracts between Total, Statoil,
Petronas and GDF Suez of small nominal capacity that were created in 2007 and 2012.
 The volume of a few contracts is expressed within a range of mtpa, a maximum amount
delivered or by the number of LNG cargoes to be transported. For instance, Tokyo Gas is
supplied by Pluto LNG 1.50-1.75 mtpa, Chubu Electric receives from BG’s portfolio up to
0.40 mtpa per year and Eni arranges its shipments to Kogas in twenty-eight shipments per
year. All these contracts are signed within the last decade, a fact that mirrors the flexibility
of clauses in modern LNG contractual arrangements.
As we can see from Table 3 in 2014 fourty-seven new supply agreements were concluded, 75
percent of which were written under a long-term horizon, and the existing contract between
6
IGU (2015) distinguishes between spot and short-term market that refer to volumes traded under agreements of less
than two years and medium-market that includes contracts of more than two and less than five years. For the ease of
the reader, in this paper there will be no refer to medium-term contracts, but spot and short-term will be regarded as
one.
7
Duration above four years

29
Sonatrach and Botas was extended for ten years. Most of these contracts will exist for more than
a decade and the vast majority of the cargoes to be delivered are destined to the Pacific basin,
mainly Japan, which shows the appetite of Asia for LNG in the long run. As regards the contracts
signed for a short-term, they present a flexibility in terms of LNG volume and some of them
include an option to extend.
It is of common acceptance that short-term contracts will be the future of LNG trade and will add
further flexibility to the market. However, Gkonis and Psaraftis (2009) support that long-period
commitments will continue to hold the largest percentage in the market in the near future.
In the next section there will be an attempt to discuss the consequences of new contracting
tendencies upon LNG shipping.

30
Table 3: Contracts concluded in 2014
EXPORT COUNTRY/
EXPORTER
IMPORT
COUNTRY/BUYER
AMOUNT
(mtpa)
DURATION
(YEARS)
START TERMS COMMENTS
LONG-TERMCONTRACTS
ALGERIA/Sonatrach TURKEY/ Botas 3 10 2015 DES
extension of existing
contract
BP
JAPAN/ Tokyo
Electric
1.2 18 2017 DES
BP CHINA/ CNOOC 1 20 2019 DES
BP CHINA/ CNOOC 0.5 15 2019 FOB
BP Pavilion 0.4 20 2019 N/A
BP Indonesia
(Tangguh's Trains 1, 2,
3)
Perusahaan Listrik
Negara (PLN)
1.5 19 2015 N/A
BP KUWAIT/ KPC
6-8 shipments
per year
5 2014 N/A
COLOMBIA/Pacific
Rubiales
CM&T Portfolio 0.5 4 2015 FOB
Gas Natura Fenosa
CHILE (Mejilones)/
BHP Billion
0.5 6 2016 DES
Osaka Gas
JAPAN/ Hiroshima
Gas
0.05-0.13 15 2016 DES
MALAYSIA/Malaysia
LNG
JAPAN/ JX Nippon
Oil & Energy
0.4 10 2015 DES
MALAYSIA/Malaysia
LNG
Tohoku Electric 0.4 10 2016 DES
MALAYSIA/Malaysia
LNG (SPA Amendment)
Saibu Gas Co. Ltd.
0.39 (2014),
0.45 (2015-2028)
15 2014 DES/FOB
MALAYSIA/Petronas TAIWAN/ CPC 2 5 2015 DES
NORWAY/Statoil LITHUANIA/ Litgas 4 5 2014 DES
QATAR/Qatargas 3
JAPAN/ Tohoku
Electric
0.1-0.18 15 2016 DES
RUSSIA/Yamal CHINA/ CNPC 3 DES

31
RUSSIA/
Yamal LNG
CM&T Portfolio 2.9 N/A
FOB at a
trans-
shipment
point in
Western
Europe
Shell KUWAIT/ KPC 1-1.12 5 to 6 2014 DES
Shell
JAPAN/ Chubu
Electric
up to 12
cargoes/year
20 2014 DES
Shell GDF Suez Portfolio 0.4 20 2014 DES
Total Gas & Power
ASIA including
Singapore/ Pavilion
0.7 10 2018 DES
USA/Cheniere/Corpus
Christi Trains 1-3
Endesa Portfolio 1.5 20 2018 FOB
option to extend for 10
years
USA/Cheniere/Corpus
Christi Trains 1-3
Endesa Portfolio 0.75 20 2018 FOB
years
USA/Cheniere/Corpus
Christi Train 2
Iberdola Portfolio 0.76 20 2019 FOB
years
USA/Cheniere/Corpus
Christi Train 2
Gas Natural Fenosa
Portfolio
1.5 20 2019 FOB
years
USA/Cheniere/Corpus
Christi Train 2
Woodside Portfolio 0.85 20 2019 FOB
years
USA/Cheniere/Corpus
Christi Train 2
INDONESIA/
Pertamina
0.76 20 2020 FOB
in addition to existing
0.76 mtpa contract signed
in 2013
USA/Cheniere/Corpus
Christi Train 3
EDF Portfolio 0.77 20 2019 FOB
in addition to existing
0.38 mtpa from Train 2.
Option to extend for 10
years
USA/Cheniere/Corpus
Christi Train 3
EDF Portfolio 0.77 20 2019 FOB
years
USA/GDF
Suez/Cameron LNG
TAIWAN/ CPC 0.8 20 2018 DES
USA/Mitsui & Co.
Ltd./Cameron LNG
JAPAN/ Kansai
Electric
0.4 20 2017 DES

32
USA/Mitsui & Co.
Ltd./Cameron LNG
JAPAN/Toho Gas 0.3 20 2017 DES
USA/Mitsui & Co.
Ltd./Cameron LNG
JAPAN/ Tokyo Gas 8 cargoes 20 2020 DES
USA/Cameron LNG ASIA/ Pavilion 0.4
SHORT-TERMCONTRACTS(lessthanfouryears)
EXPORT COUNTRY/
EXPORTER
IMPORT
COUNTRY/
PURCHASER
AMOUNT
(mtpa)
DURATION
(YEARS)
START TERMS COMMENTS
ALGERIA/Sonatrach EGYPT/ EGAS 6 cargoes 6 months 2015 DES
AUSTRALIA/
Woodside/Pluto
KOREA/ KOGAS 2.2 3 Apr-14 DES
years
ENI KOREA/ KOGAS 0.4 1 Jan-14 DES
years
ENI JAPAN/ Mitsubishi 0.2 (3 cargoes) 1 2015 DES
GDF SUEZ
JAPAN/ Tohoku
Electric
0.214-0.27
2 years and 5
months
2014 DES
GDF SUEZ INDIA/ GSPC 0.3-0.33
5 months
(until end of
March 2015)
2014 DES
GDF SUEZ JAPAN/ Marubeni 0.2-0.28
7 months
(until end of
March 2016)
2016 DES
GDF SUEZ
JAPAN/ Chubu
Electric
1.04-1.47
2 years and 3
months
(until end of
March 2017)
2015 DES
Petronas LNG TAIWAN/ CPC 0.6 6 months 2014 DES
QATAR/
RasGas
UK/ E.ON Global
Commodities
0.5 3 2014 DES
year
QATAR/
RasGas
INDIA/ Petronet LNG
Ltd.
0.5 1 2014 CFR

33
QATAR/
Qatargas 2-Train 4
KUWAIT/ KPC 8 cargoes 2014
QATAR TURKEY/Botas 9 cargoes
2014/
2015
FOB: Free On Board, DES: Delivery Ex-Ship, CFR: Cost and Freight
Source: (Clarkson Research Services 2014a; IGU 2014)

34
Chapter 4:
Transformations in LNG Shipping
Moving away from trading under long-term agreements towards the spot and short-term market
has already changed the LNG market radically, but the most important fact is that this change
contributed to the globalisation of the industry. The existence of bilateral monopolies between
specific sellers and buyers is now more limited and as market liquidity increased, new players in
all segments of the LNG value chain emerged. The shift away from oil indexed pricing and strict
pricing mechanisms and the opportunity to adjust the price of gas to changing market conditions
is one of the main improvements in the market, together with the growth, albeit slow, of arbitrage.
The shipping segment has also experienced some changes and these are projected to be fostered
further. The main implications of spot market on LNG shipping are provided in the following
pages, together with the author’s estimations regarding the evolution of LNG shipping under these
new circumstances.
4.1. New Types of Charterparties
Given that until recently the LNG market was structured exclusively under long-term SPAs, if the
fleet was not owned by the gas owner/producer or importer, it was chartered from external
shipowners, under long time charter contracts, whose duration was equal to the period of the SPA.
Before analysing the changes in the LNG market, as far as charterparties are concerned, we should
first shed some light on the theoretical background of chartering.
In general, there are four types of contractual arrangements between a potential shipowner and a
charterer, each of which implies different cost allocation as well as rights and liabilities for the
parties involved. A distinctive characteristic of the LNG market had been that, especially in the
early years of the trade when independent shipowners did not exist, charterers were chartering
vessels from the minority affiliates of energy producing companies. Generally, under a voyage
charter the shipowner is obliged to carry a specific amount of cargo from port A to port B, covers

35
the capital, operating, port expenses and bunkers for the voyage and his revenue is calculated
according to the quantity of cargo transported and the freight rate per unit of cargo ($/ton). Here,
the shipowner bears both the shipping market and operational risk. A contract of affreightment
(CoA) is a variation of the voyage charter, as it has the same cost profile, but under CoA’s the
owner commits to carry volumes of cargo within a loosely determined time frame. Thus, he is able
to arrange backhaul cargoes and employ his vessels more efficiently. Both the voyage charter and
CoA’s reflect the spot market. On the other hand, under a time charter, port costs and bunkers are
to be paid by the charterer, who hires the vessel for a specific period of time, ranging from months
to years, and pays the shipowner on a weekly, monthly or yearly basis in $/day. In time chartering,
risks are distributed between the owner, who takes the operational risk, and the charterer, who
bears the market risk. Time charterparties have been used to represent the vast majority of LNG
charters. Finally, the bareboat charter resembles to leasing a vessel, as the owner has to pay only
the capital costs of the vessel with revenue that he gains from the charterer who has to cover all
the other expenses. Obviously, in this case all kind of risks are transferred to the charterer’s side.
Depending on the type of charter agreed, different forms of charterparties may be written between
the shipowner and charterer. In the oil industry, with a long history in both long-term and spot
market, there have been many forms developed within the years that are often updated in terms of
clauses, in order to mirror the changes in the market environment. For instance, BPVOY 4 and
Shellvoy 6 forms launched in 1998 and 2005, respectively, are commonly used in tankers voyage
charters, whereas the 2003 edition of ShellTime 4 form and ExxonMobil Time 2005 serve many
time-charters in the oil trade. At the same time, various forms have been published by various
shipping organisations such as BIMCO (Baltic and International Maritime Council) and
INTERTANKO.
In the LNG market the first charter form that prevails until today as a standard LNG charterparty
is the ShellLNGTime 1 form, issued by Shell in November 2005. It is based on the ShellTime 4
crude oil tanker charteparty and it is used for time and voyage charters. However, a key difference
between oil and LNG charterparties is the fact that in the latter, besides the typical provisions (e.g.
off-hire period, laytime, demurrage etc.) other significant terms must be included; these mostly
refer to cool down temperature8
, cargo boil-off rates and heel retention9
. The boil-off refers to the
amount of natural gas that is evaporated during the voyage, which according to Lee et. al. (2015),
8
Required temperature of vessel’s storage tanks when cargo loading procedure begins.
9
A certain amount of LNG cargo kept until the next loading to maintain the tanks cool. That heel is used as motor
fuel as well as a cooling medium during the ballast passage.

36
reaches 0.15 percent on modern vessels. Although some ships can re-liquefy the boiled-off gas
onboard, such as Q-max and Q-flex types, others with a steam turbine propulsion system use it as
fuel. However, as diesel electric powered vessels begin to substitute steam turbine systems, new
technologies have been found to allow diesel turbines to use LNG as a fuel, although this
technology is yet very expensive. Thus, the importance of the boil-off provision is obvious, since
it may play a determinant role in shipowner’s (time charter) or charterer’s (voyage charter) liability
of covering fuel expenses for the laden and ballast period of the trip, respectively. The maximum
allowed boil-off rate in ShellLNGTime 1 form is set in Clause 26 (g) and (h) (“Key Vessel
Performance Criteria”).
There is no doubt that ShellLNGTime 1 has been a novelty when it was first launched, as it was
fixed to the LNG market. However, it does have some main constraints (Dodds 2013):
 It may be mainly used for steam turbines, rather than DFDE (Dual-Fuel Diesel-Electric)
vessels, which currently represent the majority of the LNG fleet,
 It allows the charterer to undertake Ship-to-Ship (STS) cargo transfer operations (cargo
“swaps”) only in cases where the safety of the vessel, crew or environment is in peril
(Clause 23 (a)), although today this strategy is very common,
 It does not contain any provision regarding onboard re-liquefaction, because it was issued
before the delivery of Q-max and Q-flex vessels which were the first to carry re-
liquefaction plant fitted.
The aforementioned aspects underline the obsolesce of ShellLNGTime 1. Although it was issued
in an LNG market which at that time was exclusively operating under long-term charters, it is also
used in spot trade, as it is considered to be easily amendable. The emergence of the spot market in
the LNG industry required a new charterparty form that would match the tendencies in the market
in a more efficient way. Amendments and subsequent mistakes arising from miswriting of clauses
that would lead to disputes, could be avoided. In addition to this, the market was seeking for a
more user-friendly form than ShellLNGTime 1, where it was mentioned, for example, that the
charterer was liable for providing and paying for the necessary LNG heel, although in voyage
charter it is the shipowner’s responsibility to cover such costs (Clause 16-LNG Retention / Supply
for Operational Purposes). There is no doubt that this clause was unfair for the voyage charterer
that had hired the vessel for only a trip from port to port. Such clauses rendered ShellLNGTime 1
an owner-friendly form. Even though different agreements could be made between the two parties
to amend this clause, it is obvious that it could render the agreement more complex and time-

37
consuming. Additionally, there was the need to define clearly provisions relevant to voyage
charter, such as laytime and demurrage, and add new boiler plate clauses10
. A very simple example
that proves the necessity of a new format can be found in Clause 5 (“Bunkers and LNG Heel at
Delivery and Redelivery”), where it is stated that the charterer is liable for paying bunker costs.
Thus, the GIINGL form (VCP) which was issued in 2012 reflected the “desire for a more voyage
specific charter format” (GIIGNL 2012, p. 1), that originated from the increase in spot and short-
term trade.
A draft of the VCP was first launched in 2009, but a few material inaccuracies that it contained,
led to its substitution in 2012. For instance, in Clauses B and C (Part I) that referred to the loading
and discharging ports, respectively, there was no warranty of a safe port11
to be chosen. This
ambiguity has been addressed in the final version of the form where the phrase “one safe port” has
been added (Part I, Clause C). Also, the boil-off rate of the draft version (Part II, Clause 2) did
specify the amount of gas that the owner was allowed to use in order to steam the turbines, but the
period during which part of the cargo could be used as fuel was not stated. As a result, the GIINGL
committee in 2012 set a time window from the time of “dropping last outward pilot at the loading
port” until the “service of NOR [Notice of Readiness]12
at the discharging port (Part I, Clause M).
This period is referred to later in the charterparty as the “Sea Passage”.
However, regardless of the amendments discussed above, there are additional factors that should
be clarified further in a potential new version of the VCP; the gauging of the boil-off rate is one
of them. The charterparty does not take into account the inner-tank sloshing of LNG during
seaway, which is due to the fact that vessel tanks are occasionally partly filled and is caused by
wind and waves. Thus, given that mis-gauging of the boil-off rate may imply extra fuel costs for
the owner, a phrase should be inserted in the clause, clarifying the method of calculating and fixing
the allowable boiled-off LNG under extreme weather conditions (e.g. Beaufort Scale 5 wind) in
parts of the sea passage. Moreover, the VCP does not follow the norm of measuring LNG sale
contracts in mtpa (energy), rather than cum (volume) and one could say that it should be updated
on this aspect.
10
Clauses added in the latter part of a contractual arrangement, such as adequate tax and piracy clauses, in the case of
charterparties.
11
The safe port is a common term in charterparties and Sellers LJ defined it in the Eastern City ([1958] 2 Lloyd’s
Rep 127, p.131) as “[a] port will not be safe unless, in the relevant period of time, the particular ship can reach it,
use it and return from it without, in the absence of some abnormal occurrence, being exposed to danger which
cannot be avoided by good navigation and seamanship.”
12
Document issued by the master of the vessel and delivered to the consignor or consignee that the ship has arrived
at port and is ready for loading or discharging of cargo.

38
Other clauses that are missing from the form and to the author’s view should be included in future
charterparties could be:
 a reference to use of drugs and alcohol onboard and during charter period, in order to
comply with the standards set out in the "Guidelines for the Control of Drugs and Alcohol
On Board Ship" as published by the Oil Companies International Marine Forum (OCIMF)
in 1995,
 a reference to the International Code for the Security of Ships and of Port Facilities (ISPS
Code) and US Maritime Transportation Security Act (USMTSA) for vessels that sail in
US territorial waters and
 an ethics and anti-corruption clause.
The above clauses represent only rough examples of the clauses that should be added in order for
VCP to be aligned with modern voyage charter parties.
A new voyage charterparty (LNGVOY) is currently drafted between BIMCO and GIINGL and is
due to be released within 2015. It is supported that it will offer greater flexibility in LNG spot
trade and bring a balance of interests and liabilities for the charterer and shipowner, contrary to
VCP which was considered too charterer-friendly. It is focused on the key challenges for any LNG
voyage charterparty; i.e. the condition of cargo tanks on arrival at the load port, the ownership of
heel, the payment of boil-off rates and the allowed arrival time at the discharge port. Unfortunately,
a thorough analysis and comparison of LNGVOY to VCP is not possible, as the draft has not been
presented yet. Nevertheless, it should be underlined that concerning boil-off, the owner is again
responsible for providing a boil-off cap and compensating the charterer for any exceed, but
exceptions such as boil-off during delay caused by the charterer’s breach of contract, are taken
into account for the protection of the owner (Kaiser 2015). Also, LNGVOY has the possibility to
be part of a CoA, in contrast with VCP which is not suitable for such contractual arrangements.
The latter can be considered a significant innovation for the LNG industry, since CoA’s can have
a long-term horizon and offer to the shipowner the security of standard payments, which is a key
factor for the LNG industry, as well as the possibility to employ different ships for each route,
according to the volumes to be transported in each voyage and the projects’ restraints (port
compatibility etc.).
It will be very interesting to see the level of response that LNGVOY will have to stakeholders in
the market and whether it will be an actual threat to VCP. This of course will depend on a large

39
extent on the volumes of the spot and short market that will be traded in the near future and the
willing of gas producers to adopt a new charterparty format.
A summary of the main differences among the available forms mentioned above are provided in
the following table.
Table 4: Brief comparison of available charterparties
ShellLNGTime 1 VCP LNGVOY
Issuer Shell GIINGL BIMCO, GIINGL
Year 2005 2009 (draft), 2012 2015
Charter
Time, can be amended
for voyage
Voyage Voyage
Friendly towards Shipowner Charterer
Both parties (user
friendly)
Boil-off max rate
Defined vaguely, only
in levels
Defined specifically in
levels and sea passage
period
Not known yet
Provision for onboard
regasification
No Yes Not known yet
Reference to safe port No Yes Not known yet
Source: author’s representation
4.2. Vessel Routing and Scheduling
Each year every LNG shipping company prepares the so-called Annual Delivery Program (ADP),
a part of the carrier’s tactical planning, which consists of the scheduled voyages for each vessel of
the fleet for the next year. All details regarding loading, sailing, unloading and returning dates and
times of ships are provided for all voyages, as well as exact gas volumes to be delivered to
importers within long-term contracts. The optimal fleet schedule procedure should be determined
in a way that avoids congestion at the liquefaction and regasification plant. Additionally, sailing
speed plays a significant role in scheduling, since it determines the time of the voyage. It is more
than obvious that in the past, when spot trade was very limited, preparing the ADP was not
considered a very complex procedure for the LNG industry, given that ships had to sail on a
standardised route. Vessels were leaving the export terminal with the tanks full, unloading at the
terminal of a specific importer and returned to the producing country. This was the consequence
of vessels tied with specific export and import projects and particular buyers.

40
However, as the market changes and spot and short-term contracts represent a small, yet significant
percentage of the global LNG trade, ADPs have to include also LNG volumes to be sold on spot
terms, while at the same time abiding by the long-term contractual agreements. In other words,
while in the past the transport of cargo was one-to-one, now it is resembles more to one-to-many;
one demand port was supplied by only one vessel, whereas today we see one vessel serving
numerous import terminals. Thus, the ADP planning problem emerges (Rakke et al. 2011). The
aim is to maintain costs of transporting LNG to long-term importers at the lowest possible levels
and simultaneously maximize the revenues from short-term sales. Additionally, LNG inventory
management at both import and export terminals is more challenging. For instance, an LNG
producer has to ensure that at any given time the LNG stored at the liquefaction plant will satisfy
its lower limits, in order to be able to satisfy any spot sale that may arise, and not exceed the
maximum levels that the tanks can store. After deregulation of the LNG market in many countries
and the free access of third parties to LNG terminals, ADPs must also take into consideration the
schedules of other shipping companies, to avoid port congestion, as mentioned above. Last but
not least, the ADP has to be lean enough and able to withstand unforeseeable events, such as
extreme weather conditions, that may lead to delivery delays and significant loss of revenue for
the shipping company.
The modern LNG ship operator that has to supply both long-term importers and spot trade is acting
as an industrial and tramp operator simultaneously; the aim of an industrial operator is to ensure
the transport of all agreed cargoes by minimising costs, whereas tramp shippers focus on
maximising profits by serving optional spot cargoes (Christiansen et al. 2013). This is a significant
change for the LNG shipping sector, which until recently was planned to sail only on specific
routes and on a recurrent basis. It goes without saying that routing and scheduling LNG vessels
under these new terms becomes quite challenging. The complexity for the ADP scheduler lies on
the fact that he has to allocate the right ship for each route; a vessel of adequate capacity to supply
both a long-term contract importer that traditionally requires large quantities and a short-term or
spot importing country which may have lower demand in terms of LNG volumes. The dilemma
posed is choosing a vessel that will be big enough to serve various markets and achieve economies
of scale or a conventional vessel that will at least satisfy the needs of standard importers and less
spot trades, but will be compatible with berth capacity restraints. For this reason, one could claim
that flexibility in vessels’ design is requested for newbuilt ships, in order for them to be able to be
employed in more export and import terminals, as far as the spot trade continues its upwards
direction. Of course this requested flexibility applies on the projects of the future as well.

41
Without doubt, nowadays a shipping company that acquires diversified LNG vessels has a lot of
barriers to surpass as the spot trade increases, when the time to prepare its ADP arrives. The good
news are that long-term contracts have become more flexible, in terms of delivery practices and
allow shippers to deliver within greater time windows in a year. Simultaneously, although the
majority of vessels is still ordered under specific projects, a lot of independent shipowners and
speculative orders have arisen, which give LNG producers important flexibility to employ
available ships in the market. The influx of non-dedicated vessels in the global fleet, allows
stakeholders to easily charter a ship for spot voyages in case their fleet is employed and demand
for LNG increases.
A key factor that should be taken into account while preparing the ADP under the new trade trends
is port and berth compatibility of ships. Vessels are usually tied to specific liquefaction plants and
match only with the loading arms at the jetty of those projects. Import terminals on the other side
of the LNG supply chain are built to be able to accept vessels of specific size and cargo capacity.
The ship operator that wishes to transfer LNG volumes has to ensure in advance that a vessel that
will carry out spot deliveries will be able to approach the regasification plant according to safety
provisions. For instance, as mentioned in Section 1, Q-max and Q-flex owned by Qatargas can
call only a few ports around the world, since limited regasification projects are able to receive such
enormous vessels.
Another issue that could emerge from the development of the spot market and is related to the
ADP problem, is the need for more frequent periodic maintenance of the vessels at a dry dock.
Given that potentially an LNG ship can be employed for longer periods within the year (loaded
days at sea) by serving more spot markets, means that technical problems could happen more
often. For this reason, is it mandatory to prevent these situations and ensure the safety of the crew,
of the environment and that of the vessel, since an accident at sea or at a terminal could be
dramatic. Thus, the days off-hire increase and the ADP scheduler has to find a balance between
maintaining both safety standards and high revenues. As a vessel spends more days sailing, ballast
time also increases, as backhaul cargoes for LNG are not feasible, which entails loss of revenue
for the shipping company. Last but not least, as explained in the previous sub-section, the longer
the voyage for an LNG vessel, the higher the percentage of boiled-off gas. If the amount of LNG
evaporated surpasses the allowed amount stated in the voyage charterparty, this implies extra
voyage costs for the ship operator; a parameter that should be seriously taken into account while
preparing the ADP nowadays.

42
4.3. The development of the second-hand market
The strategy followed so far in the LNG market for new ships to be ordered for particular LNG
projects created a highly inflexible fleet and led to an almost non-existent, illiquid sale and
purchase market for LNG vessels. In numbers, from 2006 to 2010 the average number of sales
was three vessels per annum (Clarkson Research Services 2014a) and according to TradeWinds
facts (2015), in 2013 and 2014 only ten ships altered ownership in the industry. If we compare
these numbers with oil market where 146 sales were recorded in only the first half of 2015
(Clarkson Research Services 2015b), we can realise the weakness of the second-hand market for
LNG vessels.
Under traditional SPAs, all LNG ships were built for specific projects and if they were to be idled
for a short period, a substitute could not easily be found as most likely its specifications would not
fulfil the requirements of the LNG terminals. Similarly, there were cases where operating vessels
were laid-up, because they could not be diverted to other projects or sold. Even in cases when
existing SPAs were extended, new vessels were ordered, as it was considered that the previous
ships employed in the contract had a limited effective life of 25 years and could not operate for
the extra period of a renewed contract. Nevertheless, after the 1990’s it was a consensus view that
LNG vessels could operate up to 40 years. It was at that time when the second-hand market made
its first appearance (Jensen 2004; Dorigoni et al. 2009). This situation had a myriad of
consequences for the LNG shipping industry; it prevented speculative ordering of new ships,
created high entry and exit barriers for new or existing players in the market and did not allow the
four LNG shipping markets (newbuilding, scrap, second-hand and freight) to interact freely, as
happens with oil tankers (Engelen and Dullaert 2010).
Nowadays, we see all these parameters reversing and the growth of the spot market adding to the
development of the sale and purchase market. The emergence of spot market allowed new players
to enter the LNG shipping industry and engage into orders for new ships that were not locked in
duration contracts in advance. In fact, it is estimated that almost 25 percent of deliveries between
2014 and 2019 are unattached to a specific project (Brown 2014). It should be mentioned though
that the majority of speculative orders are usually engaged into a long-term SPA once delivered,
as speculators seek to limit their risk. These vessels can be theoretically employed in any route
and once the speculator decides to exit or invest in another shipping market, he can forward the
vessel to the second-hand market. Following the market sentiment and expectations for the future

43
of LNG trade, shipowners, oil producers that own vessels or speculators may divert their fleet and
minimise their risk against market fluctuations. This situation will eventually lead to a more liquid
LNG market.
Of course, the possibility for a ship to be sold and employed under a new long-term contract
decreases as it approaches the end of its operating life. However, if the demand for LNG and spot
trade are strong, that vessel could enter successfully the spot market or engage into a short-term
SPA.
It seems that the second-hand market for LNG vessels will mainly develop in the Atlantic basin,
where the LNG industry is highly deregulated, but one should not forget that USA, a net importer
of LNG, will soon turn to a shale gas exporter and might change dramatically the allocation and
share of spot and short-term trade among the basins. This change might subsequently change the
source of demand for second-hand vessels.
Another significant implication of the growth of the spot market is the fact that there will be
stronger correlation between the prices of LNG vessels sold and newbuilt. As Engelen and Dulaert
(2010, p. 322) underline, second-hand vessels were often estimated as a “depreciated fraction of
newbuilding values”, whereas the price for new vessels are usually based on the prices for new oil
tankers, the number of available yards and the size of the orderbook. As spot market will support
the sales and purchase market, the latter will function as an auxiliary driver and contribute to create
a balance between the newbuilding and freight market. In other words, as the theory suggests
(Alizadeh and Nomikos 2009) and as happens in every liquid market, prices of new vessels will
depend on the level of freight rates and second-hand vessels.
Nevertheless, it seems that currently the fears for surplus of LNG supply and overcapacity of LNG
vessels in the near future are growing stronger and there are many analysts to support this view,
such as Holmwood Consulting (Brown 2015e) and Rogliano Salles Shipbrokers (BRS) (The LNG
Journal 2015). The main reason behind these estimations is the slower evolution of new
liquefaction and regasification plants coming online, in contrast with newbuilding orders. In case
these forecasts become true, then there is no doubt that freight prices for LNG shipping with
decrease, together with prices for second-hand vessels. Lack of demand for LNG cargoes will
move prices of new vessels downwards and shipowners will have to lay up or even scrap part of
their fleet to balance in the market. Such a fact would pause the growth of the spot market and

44
subsequently weaken further the sales and purchase market to an extent that will depend on the
duration of the shipping cycle.
It should not be expected that liquidity in the LNG second-hand market will soon reach liquidity
noticed in the oil industry; this will largely depend on the level of globalisation and the entrance
of more players in the industry that could boost competitiveness.
4.4. Other Implications
The parameters discussed in the previous sub-sections of this chapter are the main implications
that will affect LNG shipping operations directly and in the short-run. In addition to those, there
are secondary implications of the spot market on LNG shipping and these will be shortly discussed
in the following paragraphs.
Firstly, the few independent shipowners that existed in the LNG market until recently concentrated
the lion’s share of the market and competitiveness among them had not been so strong, as their
operations were “locked” with specific upstream and downstream players for a long period. As
mentioned above, though, with the development of the spot market new gas carriers are
encouraged to enter the so-called “LNG Club” and thus competitiveness structure alters.
Shipowners will have to adopt new marketing strategies and build upon brand management in
order to attract customers that wish to buy or sell LNG under short-term periods. Probably, the
best way to acquire a strong position in the market will be to focus on the safety of the service they
provide, as this factor is of crucial importance in the LNG industry. Of course, high-skilled and
specialised personnel is required to develop this strategy.
Secondly, risk management for LNG shipping companies will reform as spot trade develops.
Generally, engaging in long-term charters is deemed to be a risk management tool, as the company
can secure its future payments for a long time, regardless of the market circumstances, whereas
with tramp shipping the shipowner is vulnerable to future spot price risk of the freight market. The
latter entails high risk because in peak periods the shipowner may double or triple his earnings,
but when the market collapses the company may even default if it has not secured its financial
security in advance, via risk management tools.

45
Because of the illiquidity in the LNG market, the use of financial derivatives, such as freight
futures or options, has been very limited and not really necessary, as spot market was non-existent.
However, as the share of the spot market in the LNG trade increases, shipowners in the future will
have to engage into trading contracts in order to reduce or control their risk against freight rate
fluctuations (hedging). It is beyond the scope of this dissertation to analyse further this trend and
literature is very limited, but it will be really interesting to see how derivatives for the LNG market
will evolve. There is no doubt, though, that many years will elapse until the expanded use of future
contracts in the LNG shipping market.

46
Chapter 5:
Summary and Conclusions
In this thesis there has been an attempt to approach and understand the LNG market, analyse its
contractual trends that prevailed since the emergence of the industry and focus on the shift of the
market players to short-term contracts and spot trade. The background of long-term contracting,
the reasons behind it -particularly the extremely high investment costs- and the facts that led to the
new trends have been discussed thoroughly. It seems that the key facts during the past decade has
been the expansion of the “LNG Club” and the liberalisation of North American and European
LNG markets which altered the market structure and boosted competitiveness.
Given that even today the vast majority of contracts signed have an average duration of 20 years,
we realise that the path towards a robust spot market will take years. Additionally, there is no
doubt that the current overcapacity that characterises the market does not allow the spot trade to
expand accordingly, creating a bottleneck in the market and driving the freight rates downwards
(Brown 2015d). To be more specific, only a few days before this master thesis was submitted, spot
shipping rates were relatively flat at $30,000 per day for vessels between 155,000 cum and 165,000
cum capacity sailing both east and west of the Suez Canal, whereas in March 2015 rates for the
same vessels sailing east of the Canal were at $42,500 per day (Brown 2015d, a). Unfortunately,
there is not much optimism that revenues will increase in the short-run, but in the long-term if
more liquefaction and regasification capacity comes online, an increase in freight rates and
subsequent development of the spot market is expected.
As it was expected under the new market trends, the shipping leg of the LNG value chain has been
subject to chartering, operational and marketing changes, as analysed above. Regarding the new
forms of charterparties that recently appeared, namely the VCP and LNGVOY, it is quite hard to
predict whether they will substitute ShellLNGTime 1 form. The oil majors that have an
indisputable power in the industry and can force the shipowner to use the form of their preference
will indirectly determine in a large extent the success of the new formats. VCP has the advantage
that includes simple wording and, on the other hand, LNGVOY is deemed to maintain a balance
between the shipper’s and the shipowner’s interests.

Dissertation_Lydia Komini

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