2. 0!
Table of contents
Introduction 4
Technical feasibility
LNG Plant structure 5
Liquefaction Technology 6
LNG and Economies of Scale 9
Technology in place 10
Optimal Production Rates for Gas
Fields
11
Market overview
Natural gas status and expectations 20
Contractual Arrangements and Pricing 21
The Current LNG market Structure 26
LNG Supply and demand by 2015 27
Investment in New Capacity 29
An introduction to Unconventional Gas 33
Analysis by country 37
Key market takeaways 60
LNG Trading
Looking at LNG trading 61
Gas spot price – the volatility of the
past
62
LNG Trading 66
LNG vessels 68
LNG trading points of interest 69
Arbitrage Until now 73
Concution - Cyprus in an competitive
market
75
3. -!
Disclaimer
For the purpose of this report, information was sourced from presentations, analysis and reports commissioned by
international agencies and private organizations. Additionally, parts of international reports have been summarized and
used.
All sources are appropriately credited.
4. 2!
Abbreviations and
conversion factors
To a novice or a new trader, units of measurement adopted in the LNG trade can be
misleading. Produced gas in its original state is measured in volume (cubic meters or
cubic feet), but the moment it is liquefied, it is measured in mass units, usually tons or
million tons. (mt and annually mtpa). For LNG vessels, cargoes are measured in volume
terms (typically, thousands of cubic meters), and after re-gasification, it is measured in
equivalent energy of units (in millions of British thermal units, MMBtu).
An example to make it clearer, one tonne of LNG contains the energy equivalent of
48,700 ft3
(1,380 m3
) of natural gas. Therefore, at an output level of 1 million tons per
year (million tons per annum or MTPA), an LNG plant will require 48.7 bcf (1.38 bcm) of
natural gas, which is equivalent to 133 MMcf/day. Such a facility would require recoverable reserves of approximately 1 tcf over a
20-year life span, meaning that a 4-mtpa LNG train would consume an equivalent of 534 MMcfd (requiring reserves of 4 tcf over 20
years). These volume are basic requirement assumptions for an operating plant to break even at today’s prices.
LNG – Liquefied Natural Gas
NGL – Natural Gas Liquid
Mtpa – Metric tonnes per annum
Bcm – Billion cubic meters
Bcf – Billion cubic feet
Tcf – Trillion cubic feet
IEA – International Energy Agency
EIA – Energy Information Administration
IOC – International Oil Company
IRR – Internal Rate of Return
OECD – Organisation of Economic
Co-operation and Development
!
5. 3!
Introduction
The key objective of this paper is to evaluate the competitiveness of LNG originating from gas plants across Cyprus and Israel into
the global markets, as compared to a number of other countries. To achieve this aim, we have analyzed the relevant competitive
factors in three areas namely:
1.Technical feasibility 2.Market overview 3.LNG trading
In relation to technical feasibility, we have outlined the liquefaction technologies mainly in operation within these countries, while
also reviewing the pros and cons of large sized gas trains without getting into deep technical details. We went further to estimate
the optimal production rates from a gas field such as Leviathan gas field in Israel in order to determine the break-even time for an
investment of its scale.
In our market analysis, we started with an overview of the major game changers for the current gas market in these two countries,
in addition to analyzing each of the major market players more closely. Going further, we evaluated the expected regasification and
liquefaction capacity to gain an understanding of how this will affect the market in the future.
For LNG trading, we took a look at the recent gas price movements on a global and local scale, including the major selling and
pricing strategies adopted by LNG traders and we have also given some examples of arbitrage opportunities and explained the
requirements needed to exploit them.
In concluding this research, we have included an update of gas fields under development in Cyprus, resulting in a limited
assessment of where the produced LNG will have the most significant impact upon international competition and future markets.
6. ! "!
LNG Plant structure
Description
The LNG conversion and delivery chain, which consists
of liquefaction, shipping and regasification, has partially
replaced the gas transportation function traditionally
attributed to interstate pipelines, making the LNG market
more economical. In the first step, which is liquefaction,
natural gas is converted from its gaseous state to a liquid
state so that much larger economical quantities can be
transported via sea going tankers. In the simplest of
terms, the liquefaction process takes raw feed gas,
removes impurities and other unwanted components,
cools the gas until it liquefies, and finally moves the liquid
into storage tanks. The LNG is then loaded onto tankers
for transportation to local and international markets.
While this sounds reasonably simple, the actual process
is quite a bit more complex. Outlined below is a closer look at the technology and costs associated with the liquefaction process. We will also
review both existing and planned liquefaction infrastructure around the world as well as the key issues affecting the future of liquefaction. The
figure below is a schematic presentation of a typical LNG plant, located close to its feed as shown by pipelines running into the facility.
Figure 1 Photo of a typical LNG liquefaction Plant
7. ! #!
Liquefaction Technology
Processing plants for natural gas liquefaction are usually constructed in modular process units referred to as trains. A train is a complete
stand- alone processing unit, but often multiple trains are built side-by-side. Train sizes currently range from less than 1 to 8 mtpa. The larger
train sizes are becoming common in new gas plants as engineers attempt to take advantage of economies of scale.
The three basic steps of the liquefaction process are as follows:
1. Removal of impurities and recovery of natural gas liquids (NGLs)
The gas supply that comes from the production field is called raw feed gas. This is
typically made up of methane; other hydrocarbons such as ethane, propane, butane,
and/or pentane; including substances such as water, sulfur, mercury, and other
impurities. The raw feed gas is delivered via pipelines to processing plants where the
gas is processed to remove impurities as well as valuable NGL’s.
The first step is pretreatment, which consists of the removal of acidic gases such as
carbon dioxide and sulfur, as well as mercury and other substances, depending on
the nature and sweetness of the gas. All of these must be removed either because
their freezing points are well above the temperature of the final LNG product (and they
could freeze and damage equipment during the cooling process), or because they are
impurities that must be removed to meet pipeline specifications at the delivery point.
Water particles and wetness are then removed via a dehydration process.
The commercial aspects of NGL’s
For many gas producers at these gas prices – across the
entire US as well as Canada – that liquid rich content is the
difference between no net cash flow, and profits.
Liquids can be two-thirds of the value of a well, and the value
created from the liquids rich wells can be as good as, or
better, than Cardium oil wells.
“Institutional investors are realizing they can buy big leverage
towards rising gas prices and still get good cash flow from
current low prices, because of the added NGL content.
An executive at one junior producer told me in a recent
interview that:
• At a natural gas price of $ 4.50 per million cubic feet
(mmcf), 40 barrels of liquids per mmcf improves
revenue to $ 7/mmcf plus.
• And at 20 barrels per million, it’s almost $6/mmcf gas
equivalent. He told me that on operating income
that’s an improvement of 40% for 20 bbl/MMcf and
close to a double for 40 bbl/MMcf.
All these economics depends on the reservoir(s) and can vary
play to play, but in my talks with several management teams
operating in Western Canada, the answer was the same.
Revenue increases 50% to 100%, and profit increases 75%-
100% or more with NGL credits.”
Keith Schaefer – Publisher Oil and Gas Investment
Bulletin
8. ! $!
2. Refrigeration of the gas to liquefied state
It should be noted that methane (CH4) is the richest gas content in natural gas responsible for its usefulness as a fuel. During refrigeration, the
methane along with other recovered gaseous components is compressed and cooled to a temperature of about 160o
C where the gas becomes
liquid. This reduces the gaseous volume by a factor of roughly 600 and is the major factor that permits LNG to be transported in large
quantities. At this point, the methane rich mixture liquefies into the final cryogenic liquid state.
Although slightly different processes are used in various liquefaction facilities, the basic cooling and liquefaction principles of each process are
similar. Different liquefaction processes include the APCI MCR Process, the Phillips Optimized Cascade Process, and the Linde/Shell Fluid
Cascade Process. The process utilized at each plant is usually a design decision and depends on various factors including the composition of
the feed gas, the availability of refrigerants, whether the NGL’s are being removed upstream, the size of the facility, requirements for
operational flexibility, and the cost/availability of power for compressors.
3. Movement of the LNG to storage and ultimately into the tanker
After the liquefaction process, the LNG is pumped into cryogenic storage tanks, which are mostly spherical shaped. These tanks are typically
double-walled, with an outer wall of reinforced concrete lined with carbon steel and an inner wall of nickel steel. The vacuum between the two
walls is insulated to prevent ambient air from warming the LNG. The LNG is stored in these tanks until a tanker is available to take the LNG to
market. After an empty tanker docks at the berth (which is located as close to the liquefaction facility as possible), the LNG is loaded onto the
tanker through insulated pipes that are attached to the tanker by rigid loading arms. Once the tanker is filled, the pipes are disconnected, the
loading arms are swung away from the ship, and the tanker is ready to sail.
9. ! %!
LNG and Economy of Scale
Historically, typical LNG liquefaction plants consist of between one and three process
trains, though some plants have had as much as six trains. In simple terms, a train
can be viewed as a standalone liquefaction unit (i.e., it is possible to shut down one
train without impacting the operation of other trains). Multiple trains add flexibility to
plant design by allowing the operator to match the number of trains online to the
amount of available raw feed gas. Today some facilities are being designed for
greater flexibility within a single train, allowing for a reduction in the number of trains
commonly required for new or expanded facilities. The figure below gives a clear
picture of the trend related to the number of trains associated with LNG plants over
the last fifty (50) years.
The difference in costs between a single train and two smaller trains which add up to
the single one in terms of capacity is substantial. Usually, the LNG processing train
represents 50% of the total facility cost for a single train facility. If the train is split into
two parallel units, the train cost increases by about 35-40%, which increases the total
facility cost by about 17-20% on the average.
In most cases, the reason for splitting process units into multiple trains is to reduce the
impact on production and profitability when a single unit goes down for maintenance
purposes or due to a breakdown. In an ideal situation, production is either running at
0% or 100% in a single train unit, while a two-train unit usually functions at 50% or 100%. Only in extremely rare cases will the production level
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Table 1 Details of LNG Plants Planned/Under
!
Figure 2 Growth Trend of Process trains at LNG plants
within the last Fifty Years
10. ! &!
for a dual-train unit be 0%.
At the same time it is important to realize that overall availability remains the same. The reason is that in a two-train unit, a single failure
reduces production by 50%, but there are twice as many items to fail. Production is nearly the same over the long run whether the plant is
single train or multiple trains, if they have the same rated capacities.
Economies of scale vs flexibility
There are different approaches to determining the optimal train size for an LNG project. Some project developers believe that larger trains will
result in economies of scale; eventually driving down costs. The Middle Eastern state of Qatar recently completed one large 7.8 mpta gas
project, reputed as the world’s first integrated LNG project.
Generally, we have noticed that the LNG marketplace is beginning to demand greater flexibility with regard to timing and amounts of gas
loaded from liquefaction facilities, as opposed to the traditional fixed-term contracts.
Plant design
To accommodate these contractual terms, LNG liquefaction plants have to be able to adapt their output to match market demand, or find a
ship and market available to purchase the spot load. This production flexibility is mainly dependent upon plant design as discussed previously
in this section. While growth in this market is unquestionably favorable for the asset owner, the flexibility now required makes the business
significantly more complicated.!
In addition to volume and timing flexibility, the evolving marketplace for LNG spot sales impacts the quality requirements of gas produced from
liquefaction. If a liquefaction facility has the ability to adjust the Btu content of the LNG as needed to suit multiple market requirements, then its
output will have access to more markets. Thus, facilities with quality/content adjustment capabilities will be more profitable in today’s buyers’
market.
11. ! '(!
While volume and product flexibility have significant impacts on profitability in today’s LNG market, environmental concerns are also important.
For instance, the Norwegian Snohvit plant completed in 2007 is the first example of a facility using electric motors instead of gas compression
in order to reduce NOx emissions. This facility will also remove CO2 from the gas stream for reinjection into the producing field to further curtail
greenhouse gas emissions. Such emphasis on environmental concerns is likely to be a trend for future LNG plants, considering the growing
importance placed on sustainable practices in today’s business world.
Technology in place
Two major factors have accounted for the substantial increase in LNG train capacity over the years as shown in Figure 2. These include
advancements in process equipment technology and cycle design. The proprietary C3-MR liquefaction process, developed by Air Products
and Chemicals Inc. has been the dominant technology for train capacities up to 5 mtpa. The bulk of LNG produced in the world today utilizes
this technology, and it has become possible to stretch this over 6 mtpa due to the technological advances which allows for introduction of
larger cryogenic heat exchangers in the liquefaction process.
LNG train capacity was further increased, reaching 7.8 mtpa with the introduction of Air Products’ AP-X! )* process for QatarGas II, which
commenced operation in 2007. Additional research indicates that single LNG train capacities up to 10 mtpa are feasible using the AP-X)*
process.
The QatarGas II LNG plant consists of two massive trains with a production capacity of 7.8 mtpa each. Here, LNG is loaded onto ships and
delivered to a re-gasification terminal, where the LNG is decompressed, reheated and converted to gaseous state for onward delivery to
consumers. Usually, re-gasification terminals are linked to dedicated storage and pipeline distribution networks which distribute natural gas to
local distribution companies or independent power plants,
12. ! ''!
Determining Optimal Production Rates for a Gas Field
To unlock maximum value from gas fields which provide feed material to LNG plant, it is extremely important to determine the optimal
production rates from the onset after all relevant production tests are done. Usually, technical analysis of the field helps to determine the
exploration potential in terms of reserves, draw down rates, gas quality and treatment options to employ etc. The key questions to be
answered regarding reserves and planned production from a gas field relate to timing, quantity and quality, in addition to considering demand
and supply forces. Other factors that influence the final decisions to be made in this regard include available facilities. Computer simulation of
the gas production profile has been utilized as a reliable option
over the years.
After establishing the presence of natural gas in commercially
viable quantities, the recoverable reserves are simulated to
generate a possible production profile. Each profile is then defined
across four phases namely the:
• Start-up phase
• Plateau phase
• Decline phase
• Abandonment.
The Monte Carlo analysis methods are about the most utilized simulation methods in the energy industry.
To understand the production performance levels for different scenarios, the simulated profiles can easily be adjusted to mirror various
depletion schemes. This is very important for risk management purposes and similar to the sensitivity analysis used in forecasts. From the
Figure 3 An indicative Monte Carlo Simulations for field production
13. ! '+!
several simulation runs, production profiles of all the economic prospects are isolated and placed at their appropriate places along the time
axis. These bright looking profiles are then aggregated to form
the cumulative production profile of that run. Next, the results
of all the aggregated Monte Carlo runs themselves are
averaged to give the expected future production profile
together with an uncertainty range expressed as one
standard.
However, due to the lack of resources, for the purposes of this
report, we will defer to the use of a modest technique, which is
the Field-by-Field Modeling technique. This model utilizes
several characteristics of the Hubbert-model; the most general
“rule of thumb”.
Cyprus Natural Gas Situation – Sample Gas Field !
!
In line with our key objectives for this research report, we will
take a look at the gas findings from Cyprus’ block 12, also
referred to as Aphrodite. The expectation is that gas deposits
here will share similar characteristics with the Leviathan gas
field, which is just 34 km away but situated within the borders
of Israel, but with expected capacity of 6 tcf , while for
Leviathan we will use capacity of 12 tcf.
Figure 4 Simulation of Leviathan gas field production
Figure 5 Simulation of Aphrodite gas field production
14. ! ',!
Based on the proximity of Block 12 to the
Leviathan field which is a prolific gas zone and the
rosy relationship between both countries, we
foresee a scenario where Cyprus and Israel will co-
operate to build a common liquefaction plant,
which will be fed by gas fields within the region.
Most likely, the gas plant will be located in Cyprus’
Vasilios region which is 160 km from the where
Leviathan and 110 from Noble’s drill platform in
region 12.
To come up with a simulation analysis, we have
applied two methods of assessing the possible
production from the Leviathan gas field. First we
used the above model to determine the peak
production
rate for a gas
fields (see
appendix II
for more
information).
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Figure 5 Geological depictions of fields (Noble Energy presentation)
Table 2 Gas field
- Production
comparables
!
15. ! '-!
To strengthen our analysis, we took production information from similar gas fields the liquefaction capacity of their associated terminals. After
that, we calculated the average and used it as a proxy in order to be reassured that we will not be out of range. Using this proxy, we arrived at
the conclusion that the most effiecent annual production will be around 400 bcmpa for Leviathan and 200 bcmpa for Cyprus’ Block 12 field.
Going by the local consumption capacity, we assume that Cyprus will keep about 20% of the annual production from this field for intenal
consumpiton. Currently, Cyprus consumes natural gas to the tune of 59000 boe daily. If we reiterpret that to natural gas is 144 bcf annually.
Based on these consumption statistics and an estimated 5% annual consumption increase, the country will need appoxiamately 1 Tcf of natual
gas over the next forty years, translating to 6.2% of Aphrodite gas reserves. To be on the safe side we will assume that Cyprus will export
only 80% of the natural gas production.
Trains required – Capex required Cost analysis
With the above analysis, we can infer that at the highest levels the liquefaction terminal will need to process 11 mtpa. If we also consider that
the two countries will want to maintain the flexibility of production and
achieve economies of scale possible from large train sizes, then we will
choose 2 trains with capacity of 5 mtpa each. Since two countries are co-
operating here, they should be able to contruct both of the trains (5 mpta)
in the first phase and the other one a few years after. Though, production
levels might be low at the start-up phase, but there will be no material
issues as two operating gas fields will be on hand to feed these two
trains. After 3-4 years, there will be a possible 2nd investment for the
other train to reach full capacity after an in-depth analysis of Return on
Investment (ROI). Though, this might happen earlier or later depending
on a number of scenarios affecting operations and sales.
Figure 6 Past CAPEX Costs for Liquefaction Plants
!
16. ! '"!
The major cost of producing LNG is the liquefaction cost. As seen in the chart above (Fig. 6), the cost trend has lows and highs. Currently, the
cost per tpa has increased significantly to about 1200$/tpa-1300$/tpa due to high cost and demand for steel, including increased requests for
new terminals. For instance, a 5mtpa terminal that could have been constructed in 2000 for $2 billion now requires $6.5 billion. This factor
contributes to the greater competitiveness of the terminals completed in between 2000-2010 as compared to future liquefaction (if the price
trend remains at the level shown in the graph). The break-even period for newer terminals would most likely be higher, especially if the base
cost of natural gas is similar to that of previous years.
However, looking at the total costs, we will break them down and try to assess at what price the proposed LNG plant will break even
The costs we will analyze in order to assess how competitive the LNG coming from cyprus will be are the following :
1. Upstream costs: The cost to get the gas out of ground
2. Transportation costs: To send the gas from the platform to the the liquifaction terminal
3. Proceessing and shrinkage costs
4. LNG losses: Losses that incure during the transportation and shipping of the product.
5. Liquefaction costs: The actual cost of converting the natural gas to liquid state.
17. ! '#!
Key assumptions
Upstream cost : Capex 250 $/tpa, Capital cost : 30%, used proportional costs from Tamar Source Noble presentation. See appendix I, III
Processing: From Alaska LNG case study by Wood Mackenzie
Transportation : Assumed pipeline to Basilikos from both gas field. Used costs from other offshore pipelines
Liquefaction: Capex 1200 $/tpa, Capital cost 12% Used current costs from Australian projects
LNG losses : From Alaska LNG case study by Wood Mackenzie
Figure 7 Israel/ Cyprus LNG cost build up estimate (in $/mmbtu)
18. ! '$!
First we would like to note that the total cost (from extraction to liquefaction) was calculated $22.5 bil, which higher compared to the
estimations in the newspapers ( $16 bil). However, still the major assumption is that both of the gas field will be able to feed the LNG
trains for 30 years. The overall cost is acceptable, even if the average liquefaction cost is more than the average ( $3/mmbtu) but this is
compensated by the transportation cost which has a lower average ( $0.3/mmbtu) as the gas fields are very close to the proposed
terminal.
Without considering transportation costs, comparing this with Australian LNG break-even cost, we see that Cyprus and Israel is more
competitive. However, the real issue will come into play when the shipping cost will be included and that will show how competitive it will
be with the LNG coming from Qatar and US.
!
Figure 8: Break-even costs in comparison with competitors from Australia
!
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19. ! "#!
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BP Statistical Review of World
Energy June 2011
IEA Natural Gas information 2011
&
China / India
Production 147.9
Consumption 172.6
Net exports/(imports) (24.7)
LNG
exports/(imports) (25)
% of LNG imports 8.4%
Russia
Production 588.9
Consumption 414
Net imports/exports 174.8
LNG
exports/imports 13.4
% of LNG exports 4.5%
N. America (US,Canada)
Production 826
Consumption 846
Net exports/(imports) (23.8)
LNG exports/(imports) (14.23)
% of LNG imports 4.8%
Europe
Production 174.9
Consumption 596.8
Net
exports/(imports) (422)
LNG
exports/(imports) (87.5)
% of LNG imports 29.5%
Japan / S. Korea
Production 3.5
Consumption 148.1
Net
exports/(imports) (144.6)
LNG
exports/(imports) (137.8)
% of LNG imports 46.4%
Trinidad & Tobago
Production 42.4
Consumption 22
Net imports/exports 20.38
LNG exports/imports 20.38
% of LNG exports 6.8%
Australia
Production 48.9
Consumption 32.3
Net imports/exports 96.8
LNG
exports/imports 25.3
% of LNG exports 8.5%
Nigeria
Production 33.6
Consumption 8.4
Net imports/exports 24
LNG
exports/imports 23.9
% of LNG exports 8%
Algeria
Production 80.4
Consumption 26.5
Net imports/exports 59.9
LNG
exports/imports 18.8
% of LNG exports 6.33%
Qatar
Production 120
Consumption 23.6
Net
imports/exports 94.9
LNG
exports/imports 77.75
% of LNG exports 26.18%
Indonesia / Malaysia
Production 120
Consumption 23.6
Net imports/exports 94.9
LNG
exports/imports 61.90
% of LNG exports 20.8%
20. ! "$!
Key facts
! Unconventional gas is a game changer as it has drastically reduced US LNG import requirements and has
already changed global LNG flows
! Europe will need to import natural gas in the future, the question remains from where
Key questions need to be answered
! How will Russian gas compete in the future?
! Will shale gas in China reduce LNG demand and change all the current forecasts?
kE
K
22. ! %"!
contributed by natural gas.
In the non-OECD countries noted above, natural gas accounts for a relatively low percentage of current energy consumption. For
instance, the Chinese government has put in place a policy that will help roughly double the energy share of natural gas to over 8
per cent by 2015. This drive will also improve energy efficiency and diversification.
Specifically, based on forecasts by Wood Mackenzie, a consistent shift to the increased use of natural gas is expected from most
regions. In this regard, it is noteworthy to mention that incremental demand from China is expected to grow to about 270 Bcm
annually in 2025 at a rate of 8.5% CAGR (compounded annual growth rate). On the supply side, based on our expectations from
the established players, countries like Australia as well as Qatar will determine the pace of the market for natural gas exportation in
the form of LNG. Also North America will be able to cover some part of its consumption needs by utilizing unconventional gas
reserves.
Contractual Arrangements and Pricing
It is common knowledge that LNG is not a commodity like crude oil. Thus, the bulk of LNG trade is conducted under long-term
supply contracts. These long-term contracts provide buyers with security of energy supply, and producers with a level of certainty
when investing in large scale, long lead-time gas projects. Long-term contracts are particularly prevalent in the Asia-Pacific market,
accounting for more than 90 per cent of the region’s exports in 2010. Ultimately, the markets develop a relative hierarchy by
geography and tenor. Different countries choose to use the long-term market, the short tenor market or a slight mix of both for
varying reasons. While some make their choice based on the need to reduce exposure to volatility, others base their choice on the
pricing structure, which is most favorable.
Historically, security of supply has been particularly important for the traditional LNG importers in the Asia- Pacific region – Japan,
23. ! %%!
Korea and Taiwan – as these economies are almost entirely reliant upon LNG imports for their natural gas supply. Though, these
markets are still
dominated by long-term
contracts, there has been
a gradual shift to more
flexible arrangements as
the LNG market has
expanded, becoming
more diverse and
competitive. Trading on a
“spot basis” and under
short-term contracts
(usually less than four
years) has risen from
around 5% to 20% of
global LNG trade over the
past decade. Generally,
this reflects the risk management strategy adopted by project owners that decide not to sell their entire output under advance
contracts due to production uncertainty, and also selling any contract-free output on the spot market.
Spot and short-term trade has been relatively prevalent in the Atlantic market, accounting for about one-third of trade in 2010.
Though, the Asia Pacific is beginning to slightly choke this market as LNG commands a greater premium for sellers in Asian
24. ! %'!
markets. In the Atlantic markets, LNG imports are small relative to pipeline trade and local gas production, and have to compete
with these alternative gas supplies. Spot trade also accounts for a large portion of inter-basin LNG trade, with cargoes in recent
years tending to flow from Atlantic producers to Asia-Pacific buyers.
Under long-term contracts, prices are mainly based on formulas
linked to a reference rate; usually the lagged price of crude oil.
Accordingly, the price per unit volume of LNG increases
(decreases) when spot price of crude oil rises (falls), usually with
a set lag of a few months. This means that gas prices are
inversely proportional to crude oil prices. However, since these
contracts are privately negotiated, the exact formulas are not
publicly available. The Japan Customs-cleared Crude price
(JCC) serves as a reference point for LNG prices Across Asia as
most negotiated contract prices are typically linked to the JCC.
Historically, it is common for contracts to be based on formulas
that are non-linear, incorporating an ‘S-curve’ that moderates the
impact of both high and low oil prices over the prevailing LNG
price. This rational behind oil index contracts is relied upon because sellers have strong belief in the system, especially since they
are long on the oil have done similar deals in the past. Moreover, oil indices are deep and have a strong track record over time, in
addition to the fact that manipulation risk is low. Finally, the Japanese have stuck with the traditional, tested and trusted pricing
mechanism, deciding not to be innovative with LNG pricing and above all the sellers seem really happy with current deal prices. To
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25. ! %(!
measure or adopt acceptable gas-indexed term deals, the very first requirement is the existence of a reputable index; which must
be deep and difficult; if not impossible to manipulate – such as the Henry Hub (HH) and National Balancing Point (NBP) systems
utilized in the United States and United
Kingdom respectively (more
information below). Also, the index
must reflect floor and ceiling economics
in the market where it is used and
provide real economic purpose to
buyers and sellers alike. The HH and
NBP concepts have satisfied this
criterion over time as they are related
to actual development costs and
alternative fuel economics.
In contrast, spot LNG prices tend to
track natural gas market fundamentals
more closely and use this information
to its advantage. Pricing details for LNG at spot markets can be easily obtained from major gas trading hubs, where competing
sources of gas, usually pipeline and LNG are priced. HH and NBP are globally renowned hubs and serve as key pricing and
delivery points for natural gas futures contracts. Due to factors such as diversity in pricing arrangements, the segmented nature of
the global market, and differences in gas quality/ quality requirements, prevailing LNG prices can vary significantly around the
world. Though, available data is limited, the highest reported LNG import price per unit volume in 2010 was around 3x the lowest
Figure 11: Inter-Dependencies between Spot prices and Contract prices
26. ! %)!
reported price (on an annual average basis). Incidentally, variation in crude oil prices across the world is much less and trades at
very close margins globally.
For some reasons, LNG prices have become more dispersed in recent years. Primarily, this has been due to varying supply and
demand developments across regions, and between the gas and oil markets. After the impacts experienced during the global
recession, oil-linked contract prices for LNG in the Asia-Pacific have risen as a result of higher oil prices. The average cost of
Japanese LNG imports from Australia has doubled since its trough levels in 2009. However, spot market LNG prices in the Atlantic
have remained relatively subdued, particularly in North America. Suffice it to note here that the Henry Hub spot price for LNG has
stayed almost constant since 2010. Based on the foregoing and other market forces, we believe that LNG and natural gas pricing
mechanisms will most likely reflect the trend of market conditions over the past five years, taking into account the prices of
competing energy sources.
Thus, it is clear that European spot prices tend to be priced relatively to oil indexed contracts and the difference in pricing between
the three big exporters will reach a limit, as more profitable arbitrage opportunities are created. In clear terms, these trends signify
the increased maturation level of the industry as global expansion in liquefaction, transportation and re-gasification capacity offer
increased flexibility and diversity of supply. However, as the studies suggest, it is not very likely that a convergence of gas prices
globally will happen within the next five years.
27. ! %*!
The Current LNG market Structure
LNG has proven itself as a viable means of
securing energy sources for buyers distant from gas
reserves and the resulting trading systems has led
to a global market segmented between the two
great ocean basins – the Atlantic and Pacific. The
Asia-Pacific market is much larger than the Atlantic
market, accounting for a higher share of both
imports and exports. However, its share of LNG
trade has declined over time, as the Middle East
has emerged as a major exporting region and a
more diverse group of buyers has emerged in the
Atlantic market.
Due to the strategic location of the Middle East is
located between the two basins; it has unrestricted access to both markets, making its gas more competitive. As of 1990, Japan
alone accounted for about two-thirds of global imports. Though, Japan’s share has since fallen, it remains the world’s largest
importer of LNG by a wide margin. Recently, China and India began importing LNG due to fast rising energy demands, receiving
their first shipments in 2006 and 2004 respectively, though each country only account for a relatively small share of world imports.
Figure 12: LNG Market Interactions between the Pacific and Atlantic Basins
!
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28. ! %7!
On the Atlantic front, a wide group of buyers have emerged, especially European nations looking to:
! Diversify supplies away from pipeline gas;
! Offset declines in local production; and
! Secure supplies for expanded gas power generation.
Currently, Qatar is the world’s largest exporter of LNG, supplying around a quarter of global exports in 2010. However, as we will
elaborate later, since 2003 major investments have seen Australian exports increase two-and-a-half-fold, and China has emerged
as a major destination for supplies from Australia.
As we can see in the market interaction flows below; after taking out Qatar, which can play a role in both basins, the interactions
are mainly regional and there is a lot of inter-independence between the buyers and sellers in each basin. Nonetheless, during the
recent years, we have seen a lot of trading happening between the different basins, though mostly through short-term contracts or
spot cargos.
LNG Supply and demand by 2016
Despite the positive prospects displayed for LNG in the previous pages, it is still not the dominant player in the gas market, though
its growth levels show great promise. For instance, in the five years leading up to 2010 (2005-2009), LNG trade grew by an
average of 7% per annum, while we experienced an unprecedented jump of 22% in 2010. Rapid growth in LNG production capacity
is likely to continue into the future, especially supported by large capital investments and growing demand. LNG projects have very
long horizons as supply contracts, are often negotiated for about 20 to 25 years, and are therefore underpinned by expectations of
29. ! %#!
long-term demand growth. Additional impetus for increased gas use will most likely come from several factors including:
! Policy initiatives to reduce dependence on nuclear power following the Fukushima disaster;
! Carbon reduction schemes; and
! The development of unconventional gas.
Due to a freeze in new LNG construction projects experienced in 2008-2009 after spot prices plunged, LNG supply is expected to
remain flat until 2014-15. On the demand side, sustained increases are expected for a variety of reasons. As we have seen, China
and Japan will definitely increase their imports. This is even more important for Japan as it is faced with limited alternatives after the
recent nuclear incident at the Fukushima plant. Moreover, the persistent decline in production volumes from the North Sea will
30. ! %$!
make Europe to seek greater energy security and try to sign more diversified contracts with buyers. Also, there is soaring demand
from consumers in the Middle East, Asia, Africa and Latin America and different countries seek increased gas use due to different
reasons. All of these reasons are further enhanced by relatively low spot prices in some situations and near completion of re-
gasification plants embarked upon a few years ago. Thus, demand is expected to remain strong for years to come.
Investment in New Capacity
The LNG market is already reaping the positive effects of the new
wave of liquefaction plants being brought online as LNG trade
increased by 25% in 2010 to reach 299 Bcm.This has been recorded
as the largest percentage increase ever experienced. Qatar, which is
centrally located between two two major LNG trading basins was the
largest contributor to additional LNG supplies and now accounts for a
quarter of global LNG supplies. This volume is twice as much as
Indonesia’s output, the second-largest LNG supplier. Growth of LNG
trade is set to continue as new plants come on stream.
Despite the sustained efforts in place to increase capacity, we notice
that supply is struggling to keep up with the ever increasing demand.
The supply lag factor remains evident as we continue to experience
slippages in projects under construction and project advancement
decisions being delayed for those still at pre-FID (Final Investment
Decision) stage.
Figure : 13 Historical Global LNG supply forecasts, Source: Wood
Mackenzie 2011
31. ! '&!
Even if we there is a will to increase capacity the experience shows us that supply is struggling to keep pace with demand. The
supply lag factor is evident as until now we have seen slippages in projects under construction and projects that are pre-FID usually
are being delayed as we see at the Wood Mackenzie’s graph.
Some reasons for this lag and key areas where they occur include :
! Overheated resource markets (Australia )
! Moratoria on new LNG projects (Egypt, Qatar)
! Requirement for additional exploration to prove gas reserves (Libya, Punta Europa (EG) LNG)
! Technical challenges (Shtokman)
! Unclear Government position on exports (Indonesia, Venezuela)
! Long winding Permit and approval processes (Australia – Gorgon)
! Partner selection / Alignment issues (Global)
In addition, project development lead-times are increasing; now reaching 48 months for a greenfield project (project that has FID
and all neccesary permits). As a result, our short to medium-term supply forecast has recently been significantly reduced to reflect
realities.
What we can expect if the forecasts came true
In order for the supply to meet the forecasted demand there is a need for an extra 174 Mtpa in new capacity, as current and
under construction production is around 326 Mtpa and the global demand in 2030 will be 500 Mtpa. This equates to :
! 35 to 40 new LNG trains (medium LNG size - 4.5 to 5 Mtpa) to be built by 2030
! 25 to 30 new LNG Import Terminals (medium size- 2 BSCFD) to be built by 2030 assuming import capacity is 2 times
supply capacity (the historical average)
!
32. ! '"!
Fig. 14: Current Liquefaction and Re-gasification Capacity
Sources : Data Datamonitor, map own
33. ! '%!
Fig. 15: Expectations for Liquefaction and Re-gasification Capacity by year 2016
Sources : Data Datamonitor, own research, map own
34. ! ''!
An introduction to Unconventional Gas
As unconventional gas will play a important role
in the future we cannot explode it from the
analysis. Therefore a short introduction thought
necessary. Generally, the usual conventional gas
is extracted by drilling into porous underground
reservoirs; aiding the gas to easily migrate into
the well bore and up to the surface using
reservoir energy or external energy sources.
Unconventional gas refers to natural gas
extracted from formations where the permeability
of the reservoir rock is so low that the gas cannot
easily flow (e.g. tight sands), or where the gas is
tightly absorbed and/or attached to the rocks (e.g.
coal-bed methane). There are many types of
unconventional gas resources, including tight gas that is of relatively poor quality, normally found in reservoirs with low porosity and
low permeability. The two principal types currently being exploited are:
(a) Coal-bed methane (CBM), and
(b) Shale gas derived from a source rock that has matured and produced gas.
Unconventional gas continues to impact gas markets, especially as their recoverable reserves estimates have doubled over the
Figure 16 : Graphic presentation of Shale gas extraction process, Source: EIA
35. ! '(!
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years; resulting in a greater positive outlook when compared to recoverable conventional gas resources. The bulk of
unconventional gas production is currently located in North America and increased interest in unconventional gas resources is
spreading across the world, but with very different outcomes. The obstacles to developing unconventional gas are diverse though,
and environmental concerns are increasingly in the spotlight and have deterred exploration in a few countries. The first step toward
exploiting unconventional gas is to evaluate resource potentials.
One great benefit attached to these very large
unconventional gas deposits is that their potential is
vast as it is a resource that has proven to be several
times greater in magnitude than conventional gas
sources. An – optimistic - study by IHS Cambridge
Energy Research Associates (CERA) posits that the
recoverable shale gas within North America could be
larger than the entire world’s gas discovered to date.
Estimates of recoverable reserves are increasing at a
rapid pace as technological advances permit better
and easier access to gas from “unconventional”
sources. The most prolific shale reservoirs are
relatively flat, thick, and highly predictable. Some
formations are so large that; once drilled, the wells are
Figure 17: Global Unconventional gas reserves, Source: Wood Mackenzie
2011
37. ! '*!
East, South East Asia, and Central Africa because they have either large conventional gas reserves (i.e. Russia and Middle East)
or lack sufficient information to carry out an initial assessment on
unconventional gas sources. Findings from this report indicate that the
unconventional shale gas resource base is contributing an additional 40%
increase to technically recoverable gas reserves globally from 16,000 to
22,600 trillion cubic feet (tcf), despite that the report represents “a
moderately conservative ‘risked’ resource” assessment for basins.
In the next chapter, when we will see the case of unconventional gas for
individual regions we will try to analyze the specific aspects and impacts for
four major economies EU , Russia , China-India, Australia, US.
Figure 19: Photo representation of shale mineral, Source: Times
38. ! '7!
Analysis by country
We would take a look at the different gas situations within relevant regions to paint a clear understanding of how their resources,
policies and current status affect the global market interactions.
Europe
In Europe, according to IEA, following recovery from the economic crunch of 2008, demand is expected to grow at more than 1%
per year leading to 2030, supported by growths in the power sector generally and by further growth in the non-power sector in
developing European countries. Existing indigenous gas production is expected to decline, falling from 170 bcm today, to about 110
Figure 20 : European natural gas production, Source: Wood Mackenzie
2011
39. ! '#!
bcm in 2020 (Source: Wood Mackenzie)
mainly because gas field in Netherlands
and UK are depleting. This will definitely
create a gap that needs to be filled by
imported LNG; which will play an
increasingly important role in Europe.
According to forecasts by Wood
Mackenzie, imported LNG volumes will
grow from 15% of total supply to over
20% in the long term. Though,
unconventional gas resources exist
within the EU, but unconventional
production is unlikely to fill a significant
gap between demand and supply for
economic and environmental reasons.
Therefore, imports will continue to be a growing part of the gas supply mix to Europe. Currently, an additional 25 Bcm of re-
gasification capacity is under construction across Europe, including the Gate LNG terminal in Rotterdam that recently opened and
represents the first liquefaction facility in the Netherlands. While most of the gas traded across borders in Europe and Asia are sold
under long-term contracts, there is a growing move towards short-term LNG contracts, spot prices and market-driven pricing
reforms.
Figure : 21 European gas requirements and new available gas, Source: Wood Mackenzie 2011
40. ! '$!
Europe Pricing
As much as three quarters of European supply is contracted and one quarter is set freely, an approach referred to as gas-to-gas
competition. However, market analysts expect a large-scale and permanent shift away from oil indexation towards the use of spot
gas price indexation. The main gas importers are becoming more insistent on such a transition, though opposition continues from
pipeline suppliers such as Russia’s Gazprom and Algeria’s Sonatrach, which are both State owned. However their negotiating
positions are becoming less powerful with Europe getting new negotiating tools and looking for alternative solutions.
Unconventional in EU
Wanting to understand the options EU has with we would look
closer the unconventional gas in Europe and what is the current
impact. Look across the European Union we understand that
several oil and gas companies, including government circles are
devising strategies not only to replicate; but also improve upon
North America’s model in relation to the production of
unconventional gas. Their main aim is to utilise this model as a
blueprint for reducing Europe’s dependence on natural gas imports.
Currently, most IOC’s are fully engaged in the acquisition drive for
land acreage holding unconventional gas resources, especially
since they missed out during the initial phase of shale development
in the United States. Aside the intention by these companies to
recover some of the lost opportunity, this land acquisition is also
Impact of additional unconventionals on Europ
Eu
0
1
2
3
4
5
6
7
8
9
10
11
12
$/mmbtu(2010Real)
LRMC North America LRMC Europe
European Oil-Indexed Price
Unconventional Gas: Costs of production
0
50
100
150
200
250
300
2010
bcm
Conventio
Potential
Source: Wood Mackenzie Source: Wood Mackenzie
Thursday, 24 February 2011
Figure 22 : Unconventional gas break even costs,
Source: Wood Mackenzie 2011
41. ! (&!
buoyed by the relatively cheaper acreage prices (approximately .50$/acre). In addition, the companies are very positive on the
future prospects of unconventional gas resources in the EU and hope to secure the best land areas, in line with strategies that will
most likely become long-term commitments. The European Council is also very upbeat about the EU’s plans to achieve self-
sufficiency and security in energy via the development of unconventional gas resources. This was restated at the European
council’sI first special energy meeting, which took place on February 4, 2011, and the probability that the region’s supply outlook for
natural gas will change within a few years is high if all things move on as planned.
However, according to Wood Mackenzie’s report on unconventional gas resources, European deposits are more complex and
deeper (up to 8 km), with less porous formations than those in North America. Considering uncertainties such as the organic
content, quality requirements, shale pressure, formation characteristics and mineralogy among others, we foresee high risk
probabilities in achieving the forecasted figures. Therefore the EU and its energy strategists will have to brainstorm to devise the
best means by which these unconventional resources can transform the European market within a short period.
Other factors that make the venture more difficult and possibly less attractive within Europe include:
! Acute environmental regulations in some European countries (most stringent environmental laws reside within the EU).
! Environmental concerns stating that fracturing of shale contaminates fresh water supplies,
! Water Scarcity: The other under-estimated obstacle connected to water is its scarcity as millions of gallons of water are likely
to be needed per well for fracturing operations
! Land Use laws: In Europe, the landowner does not receive revenues from drilling, thus the incentive to accept the
inconvenience is reduced.
42. ! ("!
Even if Europe’s shale gas potential is realized, though that is unlikely to happen within the next ten years as predicted by the
Petroleum Economist, the entire planned new import infrastructure to meet the continent’s forecast demand will still be built.
Current supply and demand indicate that the European gas market will keep tightening till around 2015-17, when it is expected that
current oversupply will disappear and higher contract / spot prices in a tighter market will lead to increased and necessary
investments in the unconventional gas sector. Thus, this indicates that significant unconventional gas production may not
materialize in Europe before 2020. Nonetheless, this perspective may still be focused too much upon the present gas market and
technological conditions, whilst overlooking the issue of uncertain future EU gas demand in contrast to older energy and gas
forecasts.
On an overall basis, reports suggest two key lessons from comparing the factors determining the success of unconventional plays;
in particular shale gas in the U.S. with the potential European outlook for unconventional gas are as follows:
! Success in unconventional plays depend greatly on in-place reserves,
! Sub-surface and surface factors should align favorably – as measured by gas break-even prices and measures of investment
return (NPV, IRR etc.).
In relation to the second point above, favorable break-even and profitability can be achieved by falling production costs or by
market gas prices rising high enough to sustain investment costs.
This detailed review of the North American success story suggests that there are a myriad of factors that ultimately determine the
viability of an unconventional gas play and hence, its production potential. However, regardless of the conservative and mixed
outlook painted for European unconventional gas development – and whether or not unconventional gas will become affordable
and sustainable in the mid-to-long term in Europe –, as we are about to see (and repeat over and over again), shale gas has
already changed the underlying dynamics of the European market even before a single well has been drilled, or a single unit of
43. ! (%!
Gas exports outside FSU (in bcm)
unconventional gas has been produced from any of the European basins.
Russia
Currently, as BP statistical review states, Russia supplies
approximately 25% of Europe’s natural gas needs. In 2009,
it exported 13.6 bcfd, which was 11% lower than traded
volumes in 2008. By the fourth quarter of 2010, Russia’s
gas exports to Europe had declined by 17% owing to a
market oversupply resulting from re-directed LNG cargoes,
and unexpected warm weather. European countries have
been at the forefront of shifting reliance on Russian gas
imports and motivational factors to this effect are both
financial and strategic; a powerful combination.
As of today, the bulk of gas from Russia exported to Europe is
done under long term contracts which are indexed to oil, at prices currently above $8.50/mcf (based on data from Tudor Pickens
and Holt). Thus, European buyers are constantly seeking; and will favor cheaper LNG sources over Russian gas until prices either
converge or contract terms become more flexible to allow purchase of smaller quantities at will. The EU importers are also very
concerned about the frequent disputes between Ukraine (transit point for almost 80% of Europe’s gas imports) and Russia, lending
greater impetus to these buyers’ desire to seek out other sources of gas supply. Regardless of the above issues, Russia is still in a
position to maintain the lion’s share of the European gas market. In a bid to maintain its market share, Gazprom recently agreed to
Figure 23 : Gas exports outside US, Source: BP Statistical
Review of World Energy June 2011
44. ! ('!
trade with gas-linked prices (presumably the NBP) for about 10-15% of volumes for its key customers over the next three years and
there are on-going negotiations for further concessions. With these concessions in place, Russia will be able to mitigate significant
share loss and remain a strong player in the European gas market place. Furthermore, Russia is aware of the threat posed by far-
flung competitors such as Qatar and Nigeria, which both possess relative LNG volume and price advantages. So, it is working very
hard to keep its place in the European market.
Based on the foregoing and the fact that commercialization of unconventional gas resources is on the front-burner for European
countries, country gas buyers are constantly seeking other options re-negotiating with Russia for contracts with greater flexibility
rather that the traditional long-term supply contracts. Thus, even as unconventional gas is yet to be produced in Europe, it is still
having major impacts on Russian gas prices and the overall market dynamics. Also, we might be able to see the first production of
this resource earlier than expected, especially if Russian gas prices remain higher than the break-even point for development of
unconventional gas within the EU. A combination of these factors and its current political appeal has the potential to make
unconventional gas development economically feasible – but not politically or environmentally as we have already seen- within the
EU in record time.
Russia strategic options
Taking all relevant factors into consideration, European unconventional gas resources may eventually be cheaper than the
relatively high prices of gas from Russia’s Arctic locations (e.g. Shtokman) and the new Siberian fields located within the Yamal
Peninsula. To stem the threat of Moscow losing significant share in Europe – note that this is currently the most important export
market for Russia’s conventional gas, representatives of the Russian government and Gazprom have resorted to a subtle political
blackmail, trying to downplay the importance of shale gas reserves in Europe. Also, they are capitalizing on the negative
45. ! ((!
implications of unconventional gas production in Europe for the environment, stating that is falls out of line with regards to the EU’s
climate mitigation efforts.
Though, this is not the only option being pursued as Gazprom is also working to diversify its overall export and model using risk
management strategies. Therefore, it is expected that Gazprom will operate in three distinguished markets going forward: (1), the
traditional European market; (2), a de-regulated and compromised domestic market; and (3), a new Asian market.
It must be noted that the proposed new eastern strategy for gas supplies to China, which is a large and growing market may not be
the total solution to Gazprom’s current challenges since China is already moving towards a more self-sustaining and reliable gas
economy for several reasons. PetroChina estimates that China may have unconventional gas deposits of about 45,000 bcm, which
is more than Russia’s currently proven conventional reserves. Also, China is more likely to be able to dictate low gas prices in
connection to coal or hub pricing, rather than paying the high premiums for gas as the Europeans do. Consequently, with the high
cost of building new infrastructure in China and the development of expensive new upstream projects in East Siberia and the
Russian Far East, diversification of gas deliveries to China will not necessarily reduce Gazprom’s exposure to Europe. When
examining the Chinese companies’ ! international energy investments, one comes to the conclusion that these have been driven
less by money-making or value-aggregation objectives and more by pure principles of energy security and diversification. In this
light, the ‘U.S.-China Shale Gas Resource Initiative’ – an initiative dedicated to enabling the U.S., as “a leader in shale gas
technology and developing shale gas resources” to enter the Chinese energy market – is another hurdle that can prevent Russian
gas from going East.
In summary, from the European side shale gas, has become as of now, a negotiating tool for Europe in a changing gas market,
thus enhancing the region’s energy supply security as an alternative for diversifying energy sources. On the other hand, China is
46. ! ()!
more likely to concentrate future efforts on its energy security agenda and bolster its local economy by producing domestic
unconventional gas rather than enter into new dependencies with expensive Russian gas supplies.
How Russia fits the picture in the SE Mediterranean basin
The question for this analysis, after seeing Rusian interest for Cyprus new explorations, is why Russia in interested in the region.
Gazprom has expressed its interest to boost its share of global LNG trade to 9 % by 2020 from about 2 % it commanded in 2010.
Its Shtokman venture (with Total and Statoil) delayed final investment decisions until December 2010 after demand for LNG in the
United States, the main target market for the project, fell
because of shale gas output. The Arctic venture has also
named Europe as a potential LNG market. Gazprom’s
Marketing & Trading arm plans to trade up to 3 million tons of
LNG in 2011, but interestingly, sourcing "less than half" of this
volume from the Gazprom-controlled Sakhalin-2 project, while
ordering the rest from Egypt, Nigeria, Qatar and Australia.
Moreover, Gazprom signed a 25- year contract with three
energy companies in India to supply 7.5m tonnes, or 10bn
cubic meters annually.
Considering all these contracts and the actions of Gazprom’s
marketing arm mentioned above, in the long run, it might be
difficult for Gazprom to handle the competition from lower cost
Figure 24: Russia LNG liquefaction plants and Cyprus/Israel
Shtokman
Yamal
Cyprus – Israel
47. ! (*!
suppliers in the Middle East, Asia and Australia, especially those that are located closer to gas markets and have a significant cost
advantage. In order to achieve the full benefits of LNG trading and compete with the other major gas exporters, Russia needs a
diversified portfolio of facilities that include regasification terminals and veral liquefaction terminals (or stakes in them). This would
enable it efficiently serve its target markets with reduced transportation costs and also take advantage of opportunities for
diversification.
On another front, Gazprom is an integrated natural gas company that aims to increase its reserves. The new gas resource base in
Cyprus is therefore an opportunity for Gazprom to increase its reserves outside of FSU. Currently, Russia maintains healthy
relations with Cyprus and both nations have several bilateral agreements. Another advantage is that co-operation between both
countries on the energy front will be a good means of strengthening geopolitical stability within the region.
Thus, Russia’s high interests in the gas exploration efforts in Cyprus will be both economically and politically rewarding. Already,
Gazprom has put in a bid in order to take part in future explorations as this can become a cost efficient way to serve markets like
India (where there is already a 25 year contract in place) and Spain. It will also help to increase its gas reserves with high quality
gas located outside FSU and move the company towards becoming a global, diversified LNG player.
48. ! (7!
China – India
Two nations, which will keep the demand for natural gas rising
for years to come, are China and India, with strong support
from their populations and increased industrialization.
According to the IMF World Economic Outlook, their GDP’s are
projected to grow by around 10% each this year and in 2012,
outperforming both Japan and Korea at 2% and 5%
respectively over the same period. Coupling the above
scenarios with both states’ support for gas use, there is
significant potential for increased LNG imports into the two
countries.
In addition to securing imports, China and India are
constructing plants to handle 20 million mt/year and 10 million
mt/year of re-gasification capacity respectively. In China two
LNG terminals, both being built by the state owned PetroChina came on stream this year. These include the 3.5 million mt/year
Rudong facility in April and the 3 million mt/year Dalian terminal in June. Three more terminals are due for completion in the next
few years. Meanwhile, India has two LNG receiving terminals under construction, building upon its existing import capacity of 13.6
million mt/year. And, like China, there are plans for a number of other re-gasification facilities in India in the years ahead. Despite
their growing economies and large populations, China and India have both faced constraints with regard to their LNG imports in the
last year. China's ability to bring in shipments was curtailed by a small number of existing import terminals and limited storage
49. ! (#!
facilities while India was limited by the low capacity of its downstream gas pipelines.
China - India Pricing
The pricing terms utilized for LNG imports into China and India are somewhat different from those used for Japanese and Korean
LNG imports. Though, import volumes into India and China are relatively small when compared to the size of their economies, but
they are growing rapidly with more recent contracts commanding relatively higher prices. For instance, the price paid by China for
gas imported via pipelines from Turkmenistan is linked to prevailing oil prices, in addition to the high capital cost of pipeline
development and transportation. These pricing arrangements are expected to remain the same in the near term, whether for
existing long-term contracts or new contracts that will be signed in the next few years. However, greater reliance on spot prices or
short- term deals involving spot gas price indexation might be on the increase; as a number of LNG cargoes were recently imported
into India based on prices linked to the US Henry Hub. This trend towards charging prices that are more market reflective to end-
users in the domestic markets of China and India and other developing Asian countries is likely to continue, leading to higher retail
prices in the long run.
Pricing – Subsidies
Indigenous LNG supplies within the Asian region are generally priced below the cost of imports due to controlled or subsidized
prices as well as lower transport costs. As demand in China and India grows, LNG imports will most likely grow at a faster pace,
raising the prospect of increased competition between European and Asian buyers and linking prices in the two regions. In the
nearest future, it is expected that gas in the form of LNG will be utilized much more than gas from intra-regional pipeline
connections. We wish to note that the most ambitious intra-regional pipeline project, the Trans-ASEAN pipeline venture seems to
have made only little progress due to competition from subsidized gas. This project was largely based on the proposed exploitation
50. ! ($!
of Indonesia’s challenging East Natuna gas field.
Shale Gas in China - NOCs and IOCs
The divergent but complementary needs of the Chinese National Oil Companies and International Oil Companies are creating a
positive effect within the LNG markets. As we have already mentioned, Chinese NOC’s particularly are desirous of becoming
experts in the exploration and development of unconventional gas. Also, they aim to buy up significant stakes in upstream LNG
projects, which they would also manage independently or as a joint venture. In contrast, the International Oil Companies have the
experience the funds and the access to these areas.
But, the important factor, which they do not currently have, is presence in the Asian market. So, they are making offers that will
grant them a foothold in China in order to market their LNG assets in Australia-Asia. Also, the IOC’s believe that unconventional
gas in China could become potentially large and they want to be strategically positioned to benefit from the largesse. This
confidence is bolstered by the presence of an existing pipeline system which is connected to nearby larger trunk lines, making
transportation faster and cheaper.
These matching needs has brought the IOC’s and Chinese NOC’s closer, increased competition between regional sellers with the
presence of several diversified gas sources including 14 re-gasification terminals, shale gas, CBM reserves and piped imports from
Myanmar, central Asia and Russia. A market cannot have it better than this.
51. ! )&!
According to a recent EIA report, China is about the largest
bearer of technically recoverable unconventional gas reserves,
holding 50% more that the United States currently has.
Therefore, there are very great prospects in the Chinese basin.
Already, Shell is into a development partnership with PetroChina
and 17 wells are in different stages of drilling, including tight gas
and shale gas wells. In the same vein, British Petroleum (BP) is
currently seeking to cooperate with Sinopec on joint shale gas
development projects in China. To strengthen indigenous
participation, the Beijing government has set up special research
projects focusing on shale gas exploration and development
technologies. To maintain the tempo and become a force to
reckon with in unconventional resources, the government put
plans in place to invest $1 billion a year over the next five years into
shale gas development, especially if the exploration drilling campaigns underway prove to be successful.
&!
"&&!
%&&!
'&&!
(&&!
)&&!
*&&!
7&&!
Unconventional gas Initially in place
(Tcf)
Figure 25 : Unconventional gas fields, Source: Wood
Mackenzie 2011
52. ! )"!
Australia
The fourth largest exporter of LNG in the
world today is Australia. Interestingly, it is the
only significant LNG exporter among OECD
nations. Australia’s LNG exports are mainly
directed to the to the Asia-Pacific countries,
western China, LNG import terminals with
close proximity and other nearby countries.
In the last few years, Australia has emerged
as the major centre for investment in LNG
production facilities. New LNG facilities under
construction globally have the potential
equivalent to nearly one-third of current
global trade. Incidentally, about two-thirds of these new facilities are located in Australia. Should these new facilities all come on
stream as expected, Australia would become the world’s second largest LNG exporter within the next few years.
Though, Australia’s gas reserves are considerably smaller some of these other regions, the nation’s overall investment climate is
rated as relatively favorable by executives of major petroleum corporations, despite its seemingly far flung location. Another key
advantage is Australia’s proximity to Asia; which is a major consumption center, especially considering the very high costs of
transporting LNG relative to most other commodities.
Figure 26: Australian LNG liquefaction projects
54. ! )'!
capacity already on-stream and currently under construction. Australia’s domination in this region and somewhat on a global basis
is due to its :
1. Relative large gas resource base
2. Attractive investment climate with a stable political atmosphere
3. Reliable LNG suppliers
4. High quality
Australia will be very focused on Asian markets due to the following reasons:
1 Demand is very strong and growing
2 It has a foothold on the markets with signed contracts
3 Lower transportation costs results in comparative
55. ! )(!
North America
Currently the largest consumer and importer of natural gas in the world, the United States has large investments in a number of
completed re-gasification plants, with some at FID stage and others under construction. It has also invested heavily in relationships
with several gas producers where it has secured gas imports for several years to come, with long term contract agreements. This is
already changing gradually as it has become economically feasible to extract it massive unconventional gas
Figure 28: North America map with proposed- ongoing
liquefaction plants, Source: Wood Mackenzie 2011
56. ! ))!
reserves. The outlook is so positive that there are even plans for some export to take place in the future, subject to government
approval. Though, it is very unlikely that any gas exports will happen before 2016. These US facilities could easily be fast-tracked
at their locations in existing LNG import terminals, where they already have jetties built and LNG storage tanks in place. Exports
from the West Coast of Canada to Asia-Pacific markets are also on track.
LNG Economics for the unconventional gas
To receive economic benefit from exporting these unconventional resources as LNG, domestic gas price has to stay low while
international LNG prices move high enough and should be flexible in pricing terms. However, if the LNG prices still have to be
LNG exports from Gulf Coast to Europe LNG Exports from Gulf Coast to Asia
Figure 29 : Unconventional gas break even costs and transportation costs, Source: Wood Mackenzie 2011
57. ! )*!
indexed to crude oil (this could change depending on market dynamics), then crude oil prices would have to remain elevated.
Generally, we must understand that there are several variables that has to be considered for us to see economically competitive
liquefaction output coming from the US.
With the very positive outlook of unconventional gas sources, North America has the potential to become a net exporter, rather than
a net importer of LNG. It might also be able to rival the Australian LNG projects by upscaling some of its numerous re-gasification
plants to liquefaction facilities in order to decrease overall costs. Doing this will give it some advantages over certain Australian
LNG projects which are bugged by high investment costs. According to statistics released by Wood Mackenzie, the cost of
converting the currently idle LNG import terminals in the US to liquefaction and export facilities could be a far cheaper option when
compared to the brand-new facilities being developed in Australia. If such a cost-effective strategy for unconventional resources
become successful, Asian buyers might be able to could get gas from the US for around $US10-$US12 per million British thermal
units (Btu), compared with prevailing prices of $US14 or higher from Australian gas fields.
Qatar
This Middle Eastern emirate is about the only nation still
capable of boosting its 77 mtpa capacity even after
completing the mega-trains on its QatarGas 2 project
which added an additional 47 mtpa. Qatar’s investment in
this project represents the largest expansion of
liquefaction capacity in the world, with the expansion
alone even larger than most Greenfield projects under
Figure 30 : Qatar ability to access the markets
58. ! )7!
construction. The size of expansion is enormous and unprecedented, from 30 million tonnes (41 bcm) per year at the end of 2008
to 77 million tonnes (105 bcm) per year in 2011, and accounting for 27% of the global total LNG trade. This scale of expansion is
really significant that it has tipped the balance within the global LNG market and even affected Qatar’s own LNG marketing
strategy, making the company re-strategize to manage its current size.
Since Qatar’s first shipment of LNG export in 1997, the country has been expanding and diversifying its market reach across the
Pacific and Atlantic basins. Originally, the QatarGas 2 expansion mega trains were planned to target markets in the United
Kingdom and United States, but diverted the bulk of production in 2006 towards the Asian markets, especially China and emerging
markets within Europe. To remain competitive in the market place, Qatar has developed differential pricing strategies in its different
markets, insisting on prices closer to or slightly indexed to oil in the North Asian markets. It is noteworthy to mention that Japanese
buyers have stuck with the company and not made any additional long-term purchase commitments beyond the original contracts
with Qatargas.
Next moves for Qatar
Qatar has developed a strict pricing and production policy for its LNG over the years and has stuck with it. We believe that this is
done for political and economic reasons; also possible since the country is very rich and with a low population base. It has imposed
production limits on the vast gas reserves within the Emirate, and is currently looking abroad to invest some of its capital to fuel
export earnings.
On possible ally in this quest might be Australia, which is the key country that import-dependent Asian buyers are banking on to
reduce their reliance on Qatari LNG. For Qatar, this could be a great investment and means of co-operation with a strong
competitor. If this happens, joint resources will greatly increase the knowhow and it will increase their powers in the market.
59. ! )#!
However this solution could face significant obstacles including the fact that remotely located LNG projects are relatively costly due
to limited support infrastructure. Also, Australia’s labor market is one of the most expensive globally with strong unions and tough
environmental regulations. More significantly, the Australian government which believes strongly in free market economics might
not want to be associated with companies or countries that limit production in order to push up prices.
Japan – South Korea
The two Asian neighbors who co-hosted the FIFA world cup in
2002, Japan and South Korea account for about 44 percent of
worldwide re-gasification capacity, which is well in excess of
their gas consumption requirements. Currently, the utilization
rates of the re-gasification plants is below average, but the
surplus capacity aids storage and transportation of LNG
cargoes especially for Japan. Also, this spare capacity makes it
possible to deliver spot cargoes to gas-fired power plants at
reasonable rates. In the last ten years, a number of LNG
trading and marketing companies have invested in LNG import
terminals across different regions within Japan in order to
arbitrage between them; thus minimizing their risk exposures.
After the devastating tsunami of March 2011, which resulted in a
serious nuclear accident at Fukushima, the overall energy mix of the Nation changed considerably and those whom had invested in
LNG terminals across regions were the better for it.
14
Shin-Minato -
Sendai City Gas
Niigata - Nihonkai LNG
Ohgishima - Tokyo Gas
Higashi-Ohgishima - Tokyo Electric
Negishi - Tokyo Gas
Sodegaura - Tokyo Gas
Futtsu - Tokyo Electric
Nagasaki - Saibu Gas
Kagoshima - Nippon Gas
Regasification plantsfJAPAN
fPoland:
• The Swinoujscie LNG terminal is scheduled to be operational in 2013 and will
start with a capacity of 5 bcm/y, to be expanded to 7 bcm/y. Construction has
alreadybegun.FirstLNGdeliveriesfromQatararescheduledtoarriveinmid-2014.
fPortugal:
• REN Atlantico, the operator of the Sines LNG terminal (Portugal) is building
a third storage tank and is expected to increase the plant’s nominal send-out
capacity from approximately 4.8 bcm/y to 7.2 bcm/y.
fSingapore:
• Singapore LNG: Developed by Singapore LNG, the Singapore LNG import terminal
is the country's first LNG regasification facility, located in Jurong Island. It is
expected to serve as a hub for physical LNG trading and regional redistribution.
Terminal will have a capacity of 3.5 mtpa which could be expanded to over
6 mtpa. Construction of the project began in March 2010 and is expected
to be completed by 2013. The terminal will have two storage tanks of 188 000 m3
each, with a send-out capacity of 3.5 mtpa as well as reloading capability.
In addition, a jetty capable of accepting the latest Q-Max vessels will also be
constructed.
terminals in 2010: one in Barcelona, one in Huelva and one in Cartagena.
fThailand:
• PTT Mab Ta Phut LNG terminal: the future terminal will have an initial 5 mtpa
capacity, which could be expanded to 10 mtpa through the addition of a third
storage tank and a second berth and will be able to receive Q-Max carriers.
The commissioning process could begin in May 2011 and the terminal could be
fully operational by July. Preliminary agreements with Qatar for 1 mtpa of LNG
have failed but PTT will buy spot cargoes for commissioning and is looking for
short or medium term supply for the period 2011-2014. Australian LNG supplies
are also under consideration.
fUnited Kingdom:
• Isle of Grain LNG terminal: the second major expansion of the National Grid
Grain LNG facility, was successfully commissioned and went live on December 1st
2010. This third phase includes a new 190 000 m3
tank, 4 additional vaporizers,
associated process plant and a new jetty capable of accepting Q-Max vessels.
• Building and commissioning of phase 2 were completed on April 2010 at the
South Hook LNG terminal. The terminal now operates at full capacity (15 mtpa).
Fukuoka - Saibu Gas
Tobata - Kita Kyushu LNG
Ohita - Ohita LNG
Yanai - Chugoku Electric
Hatsukaichi - Hiroshima Gas
Mizushima -
Mizushima LNG
Himeji - Osaka Gas & Kansai Electric
Sakai - Kansai Electric
Senboku - Osaka Gas
Yokkaichi - Chubu Electric & Toho Gas
Chita - Chita LNG & Toho Gas
Kawagoe - Chubu Electric
Sodeshi - Shizuoka Gas
60. ! )$!
Generally, there are growing concerns about the continued use of nuclear reactors for energy generation. Already, the Japanese
utility company, TepCo has tempered down on its initial forecast which stated that 48% of the country’s overall power generation
would be derived from nuclear reactors by 2018. Most likely, natural gas and LNG will fill a part of this gap and might lead t a slight
shift in balance again if Japan increases it already high LNG import requirements.
Japan LNG pricing
Due to the relative dominance of LNG in the Asian markets, pricing arrangements are mainly based on long- term supply contracts
linked to crude oil prices, as opposed to other markets. However, spot trading is becoming increasingly popular among buyers and
they are seeking greater flexibility from sellers. This is especially in the face of stiffer competition from other gas producers,
relatively cheaper spot prices on some occasions and diversified sources of gas supplies. Generally, Japanese buyers seem to be
having some form of relief from long term contracts which are usually very stiff in terms of pricing.
However, this new pricing regime is laced with a few difficulties that need to be dealt with in good time.. Firstly, the market is yet to
adopt a widely accepted spot pricing mechanism and a number of existing LNG contracts are due to be replaced or renewed. Also,
in neighboring South Korea, there is little or no incentive to move away from the current oil indexation related to LNG import
contracts as the state company, Korea Gas Corp. still holds a monopoly on imports of LNG for onward sale. Therefore, these
factors might weaken the bargaining power of Japanese buyers for a few more years until they are overcome fully.
61. ! *&!
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Key market takeaways
! Market is expected to be tight up to 2016, which will draw LNG from Atlantic to Pacific basin and this will affect the spot prices
as we will see.
! Though, large volumes of new liquefaction capacity are expected till 2016, but experience has taught us not to be too
optimistic on delivery dates for new projects
! North America is gradually moving from being a net importer to exporter of gas and might begin to compete with Australia for
a share of the Pacific markets
! The target prices in the future for long term contracts in Europe and Asia will need to take into account the effect of North
America LNG exports
! Relatively higher break-even costs for Australian LNG plants compared to Qatar, can make them vulnerable in the event of a
possible price war.
! European gas production will continue declining, reaching from 170 bcm to about 110 bcm in 2020
! European unconventional production will most likely be unable to fill the gap between demand and supply, so imports will
continue to be a growing part of the supply mix to Europe
! Europe will still be a little dependent on Russian gas, as its domestic production declines in the absence of any other reliable
option. However the unconventional gas can be useful, even while in the ground, as a negotiating weapon with Russia
! China will continue to be a major gas consumer and most likely an exporter if it is able to exploit its great reserves of
unconventional gas
! The influence of Russia, Qatar and unconventional gas will remain a key factor in determining gas prices. However, the
unexpected can happen anytime. Some possible future headlines include:
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62. ! "#!
Looking at LNG trading
Here, we will do some analysis and
comparison, with the aim of understanding
the trends that underlie the spot price of gas,
the key events that have affected it over time
and what markets should expect in the
future. Then we will go on to review actual
LNG trading and then simulate some
probable real the trading options. One major
point to note is that short-term LNG trading
patterns has become significantly important,
accounting for more than a fifth of current
total trade. While a number of factors seem
to be responsible for this change, the
potential for LNG sales in highly liquid and transparent markets such as the US and UK has been critical together with the
willingness of the traders to exploit all opportunities created.
Things to remember
! Parity in Oil and Gas market dynamics maybe approaching as demand increases in the coming years while
supply is stagnated
! Exploitation of LNG arbitrage strategies require cargo availability, ship availability and re-gasification capacity
! Cyprus/Israel LNG will have cost advantage to supply Europe
! Europe and Africa will need to compete intensely for buyers in India’s lucrative LNG market
63. ! "$!
Gas spot price –volatility over the years
A close look at the history of spot gas prices
reveals some key observations and trends that
have been synonymous with the markets over
the years.
1. In 2009 prices started falling. This major
driver of this price drop was the waning
influence of large producers and key
wholesalers to dictate the terms of long-
term gas supply contracts based on oil-
indexed prices as buyers sought greater
flexibility. Also, there existed greater
commercial incentives to operate at
discounted prices in spot markets.
2. A global surplus of LNG cargoes in 2010 sent
European spot prices southward to converge
with US Henry Hub prices.
3. Though, overall demand increased in 2010 and 2011, increased exploitation of unconventional gas resources almost
resulted in self-sustenance in the US. This precluded further imports and that kept HH spot prices at the same levels. On the
Figure 31: Natural gas prices, Source: Reuters
64. ! "%!
other hand, NBP spot started to rise and equaled the EU’s oil linked contract prices.
4. The defining event which impacted gas pricing dynamics in 2011 has been the Japanese earthquake of March. The sudden
shut-in of 12GW of nuclear capacity from Fukushima resulted in a rapid increase in Japanese LNG imports to meet up with
new requirements for gas-fired generation demand (about 60% of the fuel requirements to fill this gap is likely to be met long
term by LNG imports).
5. Here, we can see that the increased
premium for LNG in Japan over Europe
drives LNG cargos to Japan.
6. In the forward curve shown, we can see
clear seasonality for European spot prices
that are absent in the US. This is mainly due
to the lack of storage facilities in Europe
which would have kept price volatilities in
check.
7. Current market dynamics indicate that the
markets expect demand for LNG from Japan
to remain high over the next few or more
years.
8. Finally, the high price margins between the
EU and US leave room for exploitation by sellers, especially if unexpected incidents cause increases in the EU spot price.
Figure 32: LNG overcapacity vs gas to oil spread, Source: Exane BNP
(September 2011)
65. ! "&!
The Exane’s graph above gives us an approximate
picture of how happenings in the LNG market has and
will affect the gas to oil spread leading to 2013.
Historically, we have seen that gas prices are strongly
influenced by tightness in the global LNG market.
Based on the data from Exane, LNG prices drop
(relative to oil) when there is an LNG overcapacity.
However, since LNG market tightness is expected
until 2012-2013, Exane’s analysts are of strong belief
that this will make the premium to increase again,
similar to 2006 figures. The main argument against
this is that the recession will continue. However, even
if this is the case, LNG consumption growth has
historically demonstrated a 5% markup to GDP growth in most years as we see in the Exane BNP Paribas graph to the left.
Figure 33: LNG overcapacity vs gas to oil spread, Source: Exane BNP
estimates (September 2011)
67. ! ""!
LNG Trading
As we noted in the introduction, short-term LNG trading was really
insignificant in the past but now plays an increasing role in the gas
market shown in the the chart from Wood Mackenzie. Major short-
term players are active in the market for a variety of reasons. From a
strategy standpoint, perhaps the most interesting case is BG group,
which employs a flexible portfolio approach to LNG trade. In this
approach, a diverse asset base is integrally managed, constantly
optimizing profits using varying models and a bias toward flexibility.
Until recently, short term trading was limited as the bulk of LNG
demand was committed to long term contracts in order to mitigate
the risks for investor. The key type of cargo sales that existed at the
time included:
! Ramp-up volumes: This simply refers to a progressive
commitment of LNG supplies from the start of a liquefaction
project’s life until the long-term contracts attain their full volume
commitments. These long-term contracts often took several
years to reach full volume since buyers could not immediately
absorb all the LNG from the new trains.
! Volumes above long-term gas contracts: This mainly relates to gas volumes that are left after all contractual gas-supply
commitments have been satisfied. Often, these surplus cargoes are rolled again into the long-term contracts and sold to the
Figure 35 : Source : Wood Mackenzie
68. ! "<!
same buyers under the same conditions as other sales.
As LNG has increasingly became part of the mainstream gas supplies, the short-term gas market developed at a rapid pace and
sellers have sought more contractual and supply flexibility in order to arbitrage prices between alternative LNG markets. The
advantages of short-term trade derive, at the most basic level, from the fact that gas supply and demand are volatile.
! Most importantly, gas supplies can be disrupted by natural disasters. For example, Hurricanes Katrina and Rita on the US Gulf
Coast in 2005 disrupted US gas production or unforeseen incidents such as the nuclear incident in Fukushima, which prompted
TEPCO to seek supplies from the short term LNG market.
! Sustained decline in production from existing fields and/or delays in bringing new projects onstream can cause gas supply to
drop, as occurred in recent years in Indonesia, causing shortfalls against long-term commitments.
! Demand for gas supplies can be shaped by natural events. Very cold weather in January 2008 caused Russia to curtail pipeline
gas exports to Turkey, again causing a spike in short-term LNG prices.
! Role of Institutional factors: A lack of consensus on gas market reform in Korea has caused Kogas, which still enjoys its
monopoly on imports for sale to third parties, to extemporize, favoring short term purchases over longer-term contracts. This
magnified the existing tendency in that highly seasonal market to fill in winter demand peaks with short-term procurement.
