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Cyprus – Israel LNG competitiveness study

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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

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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.

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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

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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.

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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

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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

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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 160oC 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.

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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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Figure 2 Growth Trend of Process trains at LNG plants within the last Fifty Years

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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.

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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,

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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

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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

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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

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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

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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.

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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)

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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.

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Figure 8: Break-even costs in comparison with competitors from Australia

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BP Statistical Review of World Energy June 2011 IEA Natural Gas information 2011

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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%

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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

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Natural gas status and expectations Natural gas in expected to act as a transition fuel to partly replace

crude oil consumption and support renewable energy sources as

its usage in the overall energy mix gradually increases. Natural gas

is touted as “energy of the near future” due to the reasons below:

• Its reserves exist in abundance

• it is environmental acceptable; and

• It possesses strong economic potentials of achieving it.

In addition to the reasons above, governments, corporate bodies,

investors and individuals have strong belief and have committed

themselves to it.

Currently, some countries (e.g. US) have decided to hold on to their gas

reserves for security reasons coupled with a production decline in certain

producing countries. For this reason, we might experience slight supply

contraction in the coming years, which may result in difficulty to meet

demand growth. According to the IEA’s projections, the bulk of the growth in

gas demand is expected to come from non-OECD nations. Particularly, rapid

growth is expected from China, India and Middle east, reflecting both

increased energy demand and substantial increase in the share of energy

© Wood Mackenzie

Delivering commercial insight

www.woodmac.com

Europe’s position within the global gas market – supply & demand by region

Regional Supply Growth Regional Demand Growth

0

50

100

150

200

250

300

China

Midd

le Ea

st

AP (e

xcl. C

hina)

North

Ame

rica

Euro

pe

Afric

a

FSU

Latin

Ame

rica

bcm

(@ 4

0 M

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3)

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

CAGR

(201

0 to

25)

2020-2025

2015-2020

2010-2015

CAGR (2010 to 25)

Source: Wood Mackenzie - Global Gas Service Source: Wood Mackenzie - Global Gas Service

-100

-50

0

50

100

150

200

250

300

350

400

Midd

le Ea

st

FSU

N. A

meric

a

Asia

Afric

a

Ocea

nia

S. A

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bcm

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-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

2010-15 2015-20 2020-25 CAGR (2010-25)

CAGR

(201

0 to

202

5)

3Thursday, 24 February 2011

Figure 9: Source: Wood Mackenzie, 2011 data

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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,

! %%!

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

! %'!

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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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

! %)!

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.

! %*!

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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! %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

! %#!

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

! %$!

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

! '&!

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) !

! '"!

Fig. 14: Current Liquefaction and Re-gasification Capacity

Sources : Data Datamonitor, map own

! '%!

Fig. 15: Expectations for Liquefaction and Re-gasification Capacity by year 2016

Sources : Data Datamonitor, own research, map own

! ''!

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

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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

! ')!

expected to flow produce gas at a steady rate for decades. Generally, it has been established that the flow rates of shale gas wells

are considerably lower than that of their conventional peers, but once the production stabilizes, the well will produce consistently for

30 years or more.

While recoverable conventional gas resources alone are estimated to amount to about 404 tcm, overall unconventional gas sources

are estimated to be over 900 tcm (according to the US Geological Survey (USGS) and the German Federal Institute for

Geosciences and Natural Resources (BGR)). From this estimated 900 tcm, at least 380 tcm appear to be recoverable, bringing the

total of recoverable conventional and unconventional gas resources to nearly 800 tcm; which is equivalent to about 250 years of

current production volumes. However the question remains at what price of oil this ventures are considered economically feasible.

Outside of the U.S, due to the lack of sufficient

geological information and credible exploration

drilling test data, the prospects for unconventional

gas production remain uncertain for at least the next

2-5 years. The Energy Information Administration

(EIA) recently published a report commissioned by

Advanced Resources International, which offers a

fresh look into the initial assessment of global shale

gas resources. The report analyzed 48 shale gas

basins across 32 countries, containing almost 70

shale gas formations. However, this report excluded

certain potential regions such as Russia, Middle

Delivering commercial insight

www.woodmac.com

© Wood Mackenzie 3

Global unconventional gas plays by location

0

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140

0% 5% 10% 15% 20% 25% 30% 35% 40%

Post Tax IRR

Co

mm

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Resourc

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cf) North America

Asia

Australia

Europe

European unconventional gas plays in context

Marcellus NortheastHorn River

European Tight / Shale

Haynesville

Barnett

Marcellus Southwest

Australia CBM

Figure 18 : Unconventional plays relative to IRR, Source: Wood Mackenzie 2011

! '*!

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

! '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

! '#!

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

! '$!

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 © Wood Mackenzie

Delivering commercial insight

www.woodmac.com

Impact of additional unconventionals on Europe’s production outlook

Europe – Impact of Unconventional production

0

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European Oil-Indexed Price

Unconventional Gas: Costs of production

0

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200

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2010 2015 2020 2025 2030

bcm

Conventional Production Unconventional Production Potential additional unconventional

Source: Wood Mackenzie Source: Wood Mackenzie

15Thursday, 24 February 2011

Figure 22 : Unconventional gas break even costs, Source: Wood Mackenzie 2011

! (&!

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.

! ("!

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

! (%!

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

! ('!

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

! ((!

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

! ()!

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

! (*!

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.

! (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

! (#!

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

! ($!

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.

! )&!

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

! )"!

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

! )%!

As of today, the bulk of Australia's LNG output is already

tied to long-term supply contracts with Asian buyers. LNG

Projects still in the planning stage might even benefit from

the rising demand from Japan after the nuclear disasters

caused by the earthquake/tsunami. Depending on the

demand and supply dynamics, these projects might be

brought to the market faster than originally planned.

However there are several other angles that should be

considered while going on with these projects. For

instance, the rapid surge in US gas reserves due to

additional non-conventional sources has already

threatened Australia’s market share. This new gas source

even displaced some of the LNG volumes shipped out from

Qatar (which holds the top spot as an exporter). There

were also fears that the Qatari could decide to swamp Asian markets with its cheap LNG and reduce volume sales by Australian

companies. However, Qatar has shown strict discipline and stuck with a standard pricing regime, preferring instead to defer

production rather than sell at lower prices. Being one of the richest nations in the world, Qatar can afford to stick with this policy for

a while and still break even at higher prices in the future, especially if demand surges.

Due to comparative advantage, Australia will still continue being the dominant player to fill the Pacific supply gap with over 7 bcfd of

www.woodmac.com

© Wood Mackenzie 12

Strategy with substance

0

5

10

15

20

25

30

35

40

45

2011

2013

2015

2017

2019

2021

2023

2025

bcf

d

Australia Rest of the world

…and continues to dominate the global outlook for new LNG supply due to its large gas resource base and attractive investment climate

Upstream Resource

LNG Price

Stable Regime

Gas Quality

Costs

Geopolitics

Domestic

Demand

Partner

Alignment

Reliable

LNG

supplier

‘Potential’ LNG supply*: Australia and the rest of the world

Source: Wood Mackenzie LNG Tool*Includes under construction, probable and proposed LNG capacity globally

64%

36%

Figure 27: Potential new capacity, Source: Wood Mackenzie 2011

! )'!

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

! )(!

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

! ))!

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

! )*!

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

! )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.

! )#!

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 GasHigashi-Ohgishima - Tokyo Electric

Negishi - Tokyo GasSodegaura - Tokyo Gas

Futtsu - Tokyo Electric

Nagasaki - Saibu Gas

Kagoshima - Nippon Gas

Regasification plantsfJAPAN

Massachussetts. The terminal became operational in early 2010. In 2010, Neptune LNG received two partial cargoes from Trinidad.

• In Mississippi, Gulf LNG Energy plans to start up its 5 mtpa Pascagoula LNG terminal by the end of 2011. The developers of Gulf LNG !the Crest Group, agroup of Houston-based investors! will continue to own 30% of the project,while Angolan state Sonangol will hold 20%.

At the end of 2010, 2 existing terminals (Sabine Pass, Freeport) had successfullyapplied to FERC for permission to re-export cargoes and one application was stillpending (Cameron, authorized in January 2011).

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 already begun. First LNG deliveries from Qatar are scheduled to arrive in mid-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-outcapacity from approximately 4.8 bcm/y to 7.2 bcm/y.

f Singapore:• 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 beconstructed.

f Spain:• Sagunto: the Sagunto regasification plant Saggas (42.5% owned by Gas Natural

Fenosa Group) will be expanded with the construction of a fourth LNG storagetank. The commissioning of this new tank, scheduled for the first quarter of 2012,will allow Saggas to double its initial storage capacity, to 600 000 m3.

• Bilbao: the Board of Directors of Bahia de Bizkaia Gas (BBG) has approved theconstruction of a new 150 000 m3 LNG tank, which represents a 50% increaseof the plant’s current storage capacity. The construction will start in 2011 and thenew equipment is expected to be operational by 2014.

• New storage tanks (150 000 m3) have been commissioned in several Spanishterminals in 2010: one in Barcelona, one in Huelva and one in Cartagena.

f Thailand:• 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 befully operational by July. Preliminary agreements with Qatar for 1 mtpa of LNGhave failed but PTT will buy spot cargoes for commissioning and is looking forshort or medium term supply for the period 2011-2014. Australian LNG suppliesare 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 theSouth 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 GasMizushima - 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

! )$!

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.

! *&!

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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:

!

E-%5&0//?0&4#&/),"%4/&B%4%-D624C&0235272.%54&%;@%54%3/0&

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! "#!

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

! "$!

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

! "%!

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)

! "&!

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)

! "'!!"#$%"&'()*%%

()*+,-.)/*/0.+!1.,/!0+!23!445/6!

7-./!-)018,!*,!.9!:1/.58)!$;##!!

Map with current transportation cost and gas spot prices of major markets, Source : Own, Data : Platts

! ""!

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

! "<!

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.

! "=!

LNG vessels availability Since we understand the importance of having

spare uncontracted LNG volumes in a market

and the impact spot prices can have on market

stabilization, we have to outline the resources

required and constraints faced in such markets.

Most importantly, there has to be on-demand

vessel availability to ship the product.

Transporters seemed to have positioned

themselves with spare fleet that can lift LNG

cargoes at any time, though we notice that LNG

spot charter rate is usually inversely proportional to the

availability of vessels as we see at Fearnley’s graph.

However as we have noted a clear seasonality occurs

as well with the spot rates in relation to the lack of

storage space and prevailing weather situation. This

makes buyers in Europe, Japan and S. Korea increase

their imports in the winter when gas demand for heating

Figure 36: Source : Fearnley

Figure 37: Source : Fearnley

! ">!

purposes skyrockets.

Data available from Fearnley indicates that there were acute vessel shortages in 2011, causing gas traders without access to

vessels to stay out of the market, despite the huge price differences across regions that could have brought in profits from diversion

of LNG cargoes. Moreover, the outlook for new vessels is very poor until 2013 when we expect the new builds to come into

operation. This shortage of vessels will further increase the spot price of LNG charter vessels and spot gas prices, with analysts

expecting charter rates to reach highs of $130.000 by 2013.

LNG trading points of interest

Players in the LNG market have found ways to explore profitable opportunities created from the pricing differences and the lack of

market effiecience. Some interesting practices in LNG trading that deserve futher exploration are the following:

Reloading LNG Reloading, as the name implies, is a newly introduced form of LNG cargo diversion. When this occurs, LNG cargo purchased

by one party is discharged from the vessel into a storage tank; and then a subsequent re-loading of the LNG into another vessel

takes place. Sometimes, the reloading happens immediately and after a time lag at other times. This form of LNG trading allows

buyers to make profits from far-flung customers where the original vessel will not reach or is not scheduled to go. Recent

adaptations to the Zeebrugge and Huelva terminals which allows reloading has given traders the opportunity to take advantage of

lower prices from other markets, selling to the final users at a profitable price differential. We note, however that this form of trading

is more of spot pricing.

! <;!

Portfolio optimization Portfolio optimization refers to strategies put in place to maximize profits reducing direct and indirect costs. Usually, this is the main

objective of all businesses but it is specially used in the LNG market due to the nature of the product. For instance, a company,

which possesses three secured LNG cargoes with three buyers in line to pay for each cargo, can decide whether or not to sell any

of the three cargoes at that point in time. Though, there is some form of commitment on these cargoes, but not binding. In essence,

the company has decided to optimize its portfolio on pricing and timing basis. Also, the seller can decide to optimize on quality

since the LNG cargoes may be of different origins and quality. This is referred to as an optimal “cargo-buyer” match.

Slow streaming Slow streaming is an operational strategy by which profits are maximized by reducing vessel operating costs in terms of fuel used,

and it is increasingly becoming popular among several vessel owners. When time permits and slow streaming is adopted, the LNG

laden vessel travels at slower speeds resulting in lower fuel consumption, which by extension reduces the operating costs. Slow

streaming is also most encouraged during seasonal periods when LNG vessel charter rates are lower.

Physical Cargo diversion and arbitrage In certain situations, LNG cargo diversion can be regarded as a form of arbitrage. This is usually favored by sellers when an LNG

cargo that was initially committed to a specific buyer in a certain market and with a commercial contract is diverted to a higher

priced market; and then replacing the initially contracted LNG cargo with gas from another source. Usually, such diversions can be

effected by any trading team, bank with requisite mandate or an individual trader acting as an Independent Trader. In arbitrage

related diversions, an independent trader purchases the cargo from the original buyer (though, seldom from the LNG Producer) or

gets the right to divert the cargo to another customer offering a higher price. Profit sharing agreements on arbitrage diversion varies

! <#!

according to different scenarios and the contracts in place between the participating middlemen. One such scenario is a situation

where a replacement of the diverted cargo is required and whom will be required to handle the replacement within the business

chain.

If the supplier has a contract for deliveries in the U.K. market, diverted volumes would have to be replaced by purchasing the same

quantity of gas diverted. The longer shipping distance from the supply source in Egypt to the U.S. would require additional ship

charters to maintain full off-take and delivery volumes. The U.S. Gulf Coast is over the twice the distance from Egypt as the U.K.

(one-way shipping distances of roughly 6,500 and 3,100 nautical miles, respectively). Round-trip travel time from Egypt to the U.S.

is about 30 days, including one day each for loading and offloading, compared to 15 days for the contracted deliveries to the U.K.

Thus, every cargo diverted to the U.S. from the U.K. requires that an additional month of charter be obtained to maintain full

delivery volumes to the U.S.

Arbitrage

One very important factor that aids the success of cargo diversion and arbitrage is the availability of re-gasification capacity on a

need basis. In markets where prices are at its peak, terminal owners with spare re-gasification capacity will aim to maximize profits

by also increasing facility rental rates. Traders engaged in cargo diversions and arbitrage schemes must put this in mind before

committing themselves in order to achieve the full benefits of cargo diversion.

Since there will always be some time lag between the transactions LNG would be purchased in terms of futures contracts and

options in order to hedge the price risk. The US-UK markets are two liquid markets for which you can observe the spread and we

will try to use it as examples. The scenario assumes that the player has access to a Nigerian contracted LNG cargo originally

intended to be delivered to US. The contracted obligation to US would be replaced by buying futures with expiration the arrival day

! <$!

of the cargo making the transaction neutral. Now, the original cargo would be diverted to UK at the UK National Balancing Point

(NBP) for an increased price. The only concern would to fix the selling price in order to avoid any price volatility between the

financial transaction and the physical delivery. This would be realized by buying put options for LNG, the right to sell at a fixed

price, in order to cover this exposure.

However, these are not the only issues that have to be considered. Any trader who decides to engage in physical arbitrage must be

certain that the price spread between the two markets supports the additional costs of diversion including:

(A) Additional ship charters required to maintain full volume deliveries for the longer shipping distances,

(B) Charges for access to re-gasification terminals in the U.S

(C) Cost of option needed to fix the price

Example of destination sensitivity To give a clear understanding of how sensible and profitable uncontracted LNG trading can be, we will make use of scenarios. Let’s

say we have an LNG cargo from Algeria at a spot charter rate of $90.000 per day. From Algeria, transportation costs are

$0.66/mmbtu to UK, $3.32/mmbtu to Japan and $1.99/mmbtu to India. We also know that we can secure a regasification slot at the

cost of $0.70/mmbtu in each location.

If this cargo is free from any contract terms, at present LNG prices this cargo can still go to Japan with a profit margin, though

maybe the smallest considering the transportation cost of other destinations. It would be important to draw up a sensitivity analysis

in order to determine the most profitable destination if market inputs including gas prices and charter rates change. For instance, if

charter rates rise as much as $110,000 per day or the Indian spot price increases by 20c/mmbtu, then the most profitable

destination would be India.

! <%!

In a situation that the cargo had been initially contracted to go to the UK, we would need to calculate the margin required in each

market to make the diversion profitable. Also, we would need to

buy an equivalent volume of gas from NBP at $10.4 in order to

replace the diverted cargo. The margins with the other markets

mentioned are outlined in the table :

Thus, if the diverting party has adequate re-gasification capacity in each of these ports, this cargo would be diverted to China, as it

offers the highest margin. The total profit from this transaction would be around $8.2 million and it would need to be split between

the seller and the original buyer, who sanctioned the diversion.

Arbitrage Until now In the past, traders utilizing the LNG arbitrage option and

with access to adequate supply have been enormously

successful trading between North American and European

markets with differential prices swinging as much as

$5/MMBtu on some occasions.

Snippets from BG’s 2007 presentation on the LNG

segment stated that: “In shipping and marketing, total

operating profit increased by £72 million to £130 million,

reflecting a 36% increase in managed volumes and higher

Price margin With Transportation costsSpain 0.5 0.13India 4 2.01Japan 5.6 2.28China 5.6 2.53

EU vulnerability to LNG cargo diversions%

Table 3 , Destination margin per mmbtu

Figure 38, EU vulnerability to LNG cargo diversions%

! <&!

margins as BG Group redirected its flexible supply portfolio to access strong demand in Asia.”

The Atlantic LNG market is liquid in terms of resources and facilities. Due to the presence of domestic production facilities and

pipeline supplies to all major LNG markets, cargoes can be swapped and traded in and out of different destinations within the

Atlantic. Though, destination clauses present in some old sales contracts limit expensive arbitrage activity.

Over the years, we have learned that traders must possess enough financial resources to in order to be able to deal with all the

technicalities involved with cargo diversion. Also, trader have to take into account the high fixed costs associated with an

independent arbitrage strategy, from ensuring the existence of re-gasification availability and the impact of high sensitivity related to

the average NYMEX-NBP spread

that varies from year to year.

Figure 39: Expected gas demand and how it evolves in the future Source: Wood McKenzie %

! <'!

Cyprus Originally, Noble Energy planned to develop and monetize the gas reserves of Leviathan using three different models, as depicted

in the company’s presentation in 2010 (shown below). The three models involved:

1. Exporting the gas through a pipeline from Turkey to central Europe

2. Selling CNG to Cyprus and the Greek islands

3. Producing and selling LNG to Europe and markets East of the Suez Canal. However, as we have seen events unfold, any co-operation with Turkey seems very unlikely as Turkey may decline to act as a

transit nation for Israeli gas resources due to the current strain in relations with Israel. The CNG option which is the second is also

unrealistic at present as Cyprus, which is on its way to becoming a producer and exporter of gas from its Block 12 finds. Therefore

the only realistic and most probable option for Leviathan gas might be a small portion in CNG exports to Greece and the vast

portion of LNG

exports using the

third model.

Figure 40: Original plans to monetize gas reserves Source: Noble energy presentation in 2010

148

Key Markets Accessible from Eastern MediterraneanMultiple export options

Existing Pipeline

Planned Pipeline

Current Gas Discoveries Expect to Fulfill Israel Demand

Significant New Gas Discovery Will Trigger Gas Export Projects

Close Proximity to Oil-linked Markets

! <"!

However, Leviathan LNG coming the liquefaction plants has to be economically attractive in order to clinch long-term contracts from

buyers. In the Pacific markets, the numbers usually favor LNG exports when the global oil price is higher than $75/bbl oil and Asian

firm contract pricing reflects a 13%(+) oil indexation** (indexation for firm contracts today is approximately 14.85%), as it is currently

situation. Thus, this project must ensure that its total operation costs per unit volume lie below these statistical assumptions.

The projected delivery cost structure around $10.8/MMBtu (7.7/MMBtu break even + 3.1/MMBtu transportation cost) to Asia is

lower when compared to some Australian LNG projects. Therefore, the proposed Cyprus Israel LNG exports considering that it will

have substantial upstream cost advantages relative to Australian LNG will be able to face the higher transportation costs. However,

some upcoming Australian projects and proposed North American LNG exports which are expected to deliver LNG to Asia at costs

of between $10 - $12/MMBtu under current gas price assumptions, are close to securing Final Investment Decisions (FID).

Figure 41 : Natural gas break even cost for Asia pacific an Europe gas demand and how it evolves in the future Source: Own, Wood McKenzie %

! <<!

This expected new demand will be satisfied on a first come-first serve basis. Therefore, in the case of Cyprus-Israel LNG project,

investors will expect to view Asia as a perspective market they will need to secure the second wave of demand from Asia and

specifically from India and China that are expected to increase their consumption in the future and as we see at the chart the LNG

price from Qatar is the most competitive. However, as we have seen in the past with North America’s, big importers became

unexpectedly exporters, so looking at China there must be conscious looking the evolutions with the exploration of unconventional

gas. On the other hand, India is a market at which Cyprus has a clear cost advantage over Australia and the big concern is new

LNG capacity from Qatar that has

lower cost structure and more

flexibility in pricing.

On the other hand, Cyprus-Israel

possess a clear advantage over

their competitors in the Atlantic

basin ($8.1/MMBtu - 8.5/MMBtu)

Here, Australia can be pushed out

of the picture as the main

competition will come from three

places namely piped gas,

unconventional gas in the form of

LNG imports from US and from

intrinsic production; and LNG Figure 42: Natural gas evolution of LNG spot price by destination, Source Waterborne (August 2011)%

! <=!

cargoes from Africa. As noted from previous analysis, Europe will be in need of additional gas imports in the coming years to cover

the increased consumption needs. Considering the fact that the Europe has decided to diversify its import sources, it is most likely

to favor the southern corridor Azerbaijan gas over piped gas from Russia and in the end, this could be the biggest competitor of

European LNG.

From the other alternative sources the unconventional gas cannot be considered a realistic solution despite the possible low cost

structure, due to the lack of technical and economical visibility. Within the LNG solution, the competition will come from African

countries and US. North America will be a small-scale exporter and given the low upstream cost, it will be possible to compete the

LNG from Cyprus Israel. However the escalation to the extend that it will make US a considerable exporter is unlikely to happen,

given the current information, due to US state energy safety concerns. Nevertheless the technological advancements and the

market responsiveness that characterize US, cannot exclude this possibility.

From the African continent, we expect that Algeria, with a high uncommitted capacity and Nigeria’s incremental capacity will target

the European market, as the transportation costs are similar to Cyprus-Israel and therefore this would be on a first come first

served basis. Even that however, is not particular worrying as with the given prices there will be demand from the European

countries. However we must not forget that the as the price chart shows us, the price to India are twice the European, therefore it

would be reasonable to say that the previous mentioned players will try to secure contracts there, before committing to any

investments, and then knock the safer, but less profitable, door of Europe.

! "#!

References

Presentations

Wood Mackenzie

Options for India in today’s gas world

Alaskan LNG Exports Competitiveness Study

Europe changing gas supply

Shifting Global Gas Dynamics

Tudor Pickering Holt & Co - LNG And The Developing Global Gas Market

CBI- Current State & Outlook for the LNG Industry

Government of western Australia - Western Australia in the LNG Zone

Fearnley

LNG Shipping Market Update

LNG arbitrage trading

!

Reports

IEA Natural Gas Information 2011

EIA International Energy Outlook 2011

BP statistical_review_of_world_energy_full_report_2011

IGU Gas Price Report June 2011

Datamonitor LNG structural changes

LNG-Technology-for-the-Commercially-Minded

Understanding Today's Global LNG Business

Large lng Trains developing optimal process cycle

Cook Inlet Natural Gas Production Cost Study

Overview of the oil and gas exploration and production process

International Group of Liquefied Natural Gas Importers – LNG Industry 2010

EUCERS – Strategic perspective of unconventional gas : A game changer with implication for the EU’s energy security

Oxford institute for energy studies -The Nature of LNG Arbitrage, and an Analysis of the Main Barriers for the Growth of the Global LNG Arbitrage Market

!

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Appendix I LNG Cost structure

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Appendix III Cost assumptions

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Appendix IV Transportation cost

Technical AssumptionsConsumption of fuel oilt/day 30 Calculation: Cost of charter for the entire voyage, accounting for aShip's Cargo mmtbu 3270000 round-trip and a two-day delivery time, and dividing that cost by theLost gas per day 0.14% total delivered cargo in MMBtu; the cost of boil-off by multiplyingUtilization rate 98% the volume lost by the delivered price, divided by the delivered cargo

size in MMBtu; the cost of bunker oil by multiplying Platts bunkerMarket assumptios fuel assessment in $/mt by the consumption rate, and then half theCargo daily rate$/day 90000 round-trip voyage time (the remainder being fueled by boil-off gas).LNG spot price$/mmbtu 13 The delivered cargo size is calculated by multiplying the initial cargoShip oil price $/t 730 size by itself minus the boil-off rate powered to the trip length, and

then multiplied by a utilization rate of 98%.Voyage Days

Japan/Korea S China/Taiwan West India Southwest Europe Northwest Europe Northeast US ArgentinaME 15 13 3 13 16 22 21Australia 8 7 9 21 24 29 21Trinidand 33 31 22 9 9 5 11Nigiria 26 23 17 9 10 13 11Algeria 24 22 13 1 4 9 14Belgium 28 25 16 3 - 8 16Peru 21 24 27 23 24 24 9Russia 3 5 15 27 29 35 27

Source Platts Rates uses Suez canal, ands one day extra for shipping and 24 cents/MMBtu for canal fees

Charter cost Japan/Korea S China/Taiwan West India Southwest Europe Northwest Europe Northeast US ArgentinaME 0.94 0.82 0.23 0.82 1.00 1.38 1.31Australia 0.52 0.46 0.58 1.31 1.51 1.83 1.31Trinidand 2.10 1.97 1.38 0.58 0.58 0.34 0.70Nigiria 1.64 1.44 1.06 0.58 0.64 0.82 0.70Algeria 1.51 1.38 0.82 0.11 0.28 0.58 0.88Belgium 1.77 1.57 1.00 0.23 0.52 1.00Peru 1.31 1.51 1.70 1.44 1.51 1.51 0.58Russia 0.23 0.34 0.94 1.70 1.83 2.24 1.70

Fuel cost Japan/Korea S China/Taiwan West India Southwest Europe Northwest Europe Northeast US ArgentinaME 0.43 0.37 0.08 0.37 0.46 0.64 0.61Australia 0.22 0.20 0.25 0.61 0.70 0.86 0.61Trinidand 0.99 0.93 0.64 0.25 0.25 0.14 0.31Nigiria 0.77 0.67 0.49 0.25 0.28 0.37 0.31Algeria 0.70 0.64 0.37 0.03 0.11 0.25 0.40Belgium 0.83 0.73 0.46 0.08 0.22 0.46Peru 0.61 0.70 0.80 0.67 0.70 0.70 0.25Russia 0.08 0.14 0.43 0.80 0.86 1.06 0.80

Lost gas Japan/Korea S China/Taiwan West India Southwest Europe Northwest Europe Northeast US ArgentinaME 0.58 0.50 0.11 0.50 0.62 0.87 0.83Australia 0.30 0.27 0.34 0.83 0.96 1.17 0.83Trinidand 1.35 1.26 0.87 0.34 0.34 0.19 0.42Nigiria 1.04 0.91 0.66 0.34 0.38 0.50 0.42Algeria 0.96 0.87 0.50 0.04 0.15 0.34 0.54Belgium 1.13 1.00 0.62 0.11 0.30 0.62Peru 0.83 0.96 1.08 0.91 0.96 0.96 0.34Russia 0.11 0.19 0.58 1.08 1.17 1.44 1.08

Total Cost : $/mmbtuJapan/Korea S China/Taiwan West India Southwest Europe Northwest Europe Northeast US ArgentinaME 1.95 1.69 0.42 1.69 2.08 2.89 2.75Australia 1.04 0.92 1.17 2.75 3.16 3.87 2.75Trinidand 4.45 4.16 2.89 1.17 1.17 0.67 1.43Nigiria 3.44 3.03 2.21 1.17 1.30 1.69 1.43Algeria 3.16 2.89 1.69 0.18 0.54 1.17 1.82Belgium 3.73 3.30 2.08 0.42 1.04 2.08Peru 2.75 3.16 3.58 3.03 3.16 3.16 1.17Russia 0.42 0.67 1.95 3.58 3.87 4.74 3.58

! $)!

Appendix V Asian LNG Capacity

Country Country Company Status Capacity (bcm / year)

Capacity (m3

(N)/hour)Storage Trains Comments

1 India Dahej Petronet LNG Operational 13.79 _ _ 6 _2 India Hazira Shell Operational 3.50 _ 320,000 2 _3 India Dhabol Gail Planned 6.80 _ 500,000 3 The terminal is expected to be operational by 2011.4 India Mundara Port Adani Planned 6.80 _ _ _ _

5 India Kochi Petronet LNG Planned 3.50 _ 320,000 2 The mechanical completion of the complete facility is expected in 1st Quarter of 2012.

6 India Jamnagar GVK Power Planned _ _ _ _ _7 India Manglore ONGC Planned 6.80 _ _ _ _

8 India Yet to be decided Reliance Planned _ _ _ _

One of the options is to set it up at Kakinada, in Andhra Pradesh, following which the under-utilised East-West

pipeline, which connects the landfall point for gas from the eastern offshore KG-D6 field to Baruch in Gujarat ,can be

used to move the fuel to the company's plant.9 India Ennore IOC Planned 3.50 _ _ _ Expected to start in 2013 - 2014

10 Japan Hakodate Minato Hokkaido Gas Company Operational _ 12,500 5,000 1 _

11 JapanLNG handling facilities of Kawagoe Thermal Power

StationChubu Electric Power Company Operational _ _ 480,000 4 _

12 Japan Himeji (Kansia, Osaka) Kansai Electric Power Company Operational _ _ 520,000 7 _13 Japan Mizushima Mizushima LNG Group Operational _ _ 160,000 1 _14 Japan Hatsukaichi Hiroshima Gas Operational _ _ 170,000 2 _15 Japan Yanai Chugoku Electric Power Company Operational _ _ 480,000 6 _16 Japan Tobata Kitakyushu LNG Company Operational _ _ 480,000 8 _17 Japan Fukuhoku Saibu Gas Operational _ _ 70,000 2 _18 Japan Nagasaki Saibu Gas Operational _ _ 35,000 1 _19 Japan Kagoshima Nihon Gas Operational _ _ 86,000 2 _20 Japan Senboku terminal II Osaka Gas Operational _ _ 1,585,000 18 _21 Japan Takamatsu Satellite Station Shikoku Gas Operational _ _ 10,000 1 _22 Japan Sakai Sakai LNG Company Operational _ _ 420,000 3 _23 Japan Yokkaichi (Chubu, Toho) Chubu Electric Power Company Operational _ _ 320,000 4 _24 Japan Sodeshi Shimizu LNG Operational _ _ 177,200 2 _25 Japan Negishi Tokyo Gas Operational _ _ 1,180,000 14 _26 Japan Futtsu Tokyo Electric Power Company Operational _ _ 1,110,000 10 _27 Japan Sodegaura Tokyo Gas Operational _ _ 2,660,000 35 _28 Japan Higashi - Ohgijima Tokyo Electric Power Company Operational _ _ 540,000 9 _29 Japan Ohgishima Tokyo Gas Operational _ _ 600,000 4 _

30 Japan Hachinohe Satellite Station JX Nippon Oil and Energy Operational _ _ 4,500 1This terminal will be replaced by a larger terminal at

Hachinohe which will be commissioned in 2015.

31 Japan Hachinohe JX Nippon Oil and Energy Planned _ _ 140,000 2 Expected to be operational by 201532 Japan Chita Chita LNG Operational _ _ 640,000 7 _33 Japan Hitachi Satellite Station Tokyo Gas Planned _ _ 650 1 Expected to be operational by 201734 Japan Shin-Minato Works Sendai City Gas Bureau Operational _ _ 80,000 1 _35 Japan Chita Midorihama Works Toho Gas Operational _ _ 200,000 1 _36 Japan Chita LNG Joint Terminal Toho Gas, Chubu Electric Power Company Operational _ _ 300,000 4 _37 Japan Senboku Osaka Gas Operational _ _ 180,000 4 _38 Japan Kushiro JX Nippon Oil and Energy Planned _ _ 10,000 1 Expected to be operational by 2015

39 Japan Shin-Sendai Thermal Power Station Tohoku Electric Power Company Planned _ _ _ _ Expected to be operational by 2016

40 Japan Wakayama Power Station Kansai Electric Power Company Planned _ _ _ _ Expected to be operational by 201841 Japan Himeji Terminal Osaka Gas Operational _ _ 740,000 8 _

42 Japan Sakaide Sakaide LNG Company Operational _ _ _ _ Became operational in 2010

43 Japan Matsuyama Satellite Station Shikoku Gas Operational _ _ 10,000 1 _44 Japan Oita Oita LNG Company Operational _ _ 460,000 5 _

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46 Japan Chikko Satellite Station Okayama Gas Operational _ _ 7,000 1 _47 Japan Yokkaichi Toho Gas Operational _ _ 160,000 2 _

48 Japan LNG handling facilities of Joetsu Thermal Station Chubu Electric Power Company Planned _ _ _ _ Expected to be operational by 2012

49 Japan Naoetsu INPEX Corporation Planned _ _ _ _ Expected to be operational by 201450 Japan Niigata Nihonkai LNG Company Operational _ _ 720,000 8 _51 Japan Ishikari Hokkaido Gas Company Proposed _ _ _ _ Expected to be operational by 2012

52 Japan Yoshinoura Thermal Power Station Okinawa Electric Power Company Operational _ _ _ _ Expected to be operational by 2012

53 South Korea Incheon KOGAS Operational _ 6,090,000 2,880,000 20 _

54 South Korea Pyeongtaek KOGAS Operational _ 5,342,400 1,560,000 14 _

55 South Korea Tongyeong KOGAS Operational _ 2,646,000 1,680,000 12 _

56 South Korea Samcheok KOGAS Under Construction _ 1,848,000 2,400,000 12 Construction period 2008-2019.

Completion of first phase by 2013.

57 South Korea Boryeong GS Caltex Planned _ _ _ _ _

58 South Korea Jeju KOGAS Planned _ _ 50,000 2 _

59 South Korea Gwangyang POSCO Operational _ 574,000 265,000 3 _

60 Australia Gorgon LNG terminal Chevron Under Construction 21.00 _ _ 2 The terminal is expected to be operational in 2014.

61 Australia Australia Pacific LNG terminal Origin Energy Limited and Conoco Phillips Planned 25.20 _ 480,000 3 _

62 Australia Pluto LNG terminal Woodside Under Construction 6.02 _ 240,000 2It is a joint venture of the Woodside (90 %), Tokyo Gas (5%) and Kansai Electric (5%). The Pluto and Xena gas fields are estimated to contain 4.8 trillion cubic feet (Tcf) of dry gas reserves and an additional 0.25 Tcf of contingent resources. 63 Australia Bonaparte LNG terminal Gdf Suez Planned 2.80 _ _ _The project partners include Gdf Suez (60%) and Santos (40%). The terminal will be floating facility. The terminal is expected to commence operation by 2014.64 Australia Browse LNG terminal Woodside Proposed 16.80 _ 280,000 3 The terminal has potential to expand its capacity to 35 bcm / year.

65 Australia Darwin LNG terminal Conoco Phillips Operational 5.04 _ 188,000 1 The project partners include ConocoPhillips, Eni, Inpex, TEPCO, Tokyo Gas and Santos.

66 Australia Fisherman's Landing LNG terminal Liquefied Natural Gas Limited Planned 4.20 _ _ _ The Project is planned in two stages, with the first stage

consisting of operating a single processing train (Train 1),

67 Australia Gladstone LNG terminal Petronas and Total Planned 10.92 _ _ _ The project partners include Petronas (27.5%), Total (27.5%) and Kogas (15%).

68 Australia Gladstone LNG terminal Arrow Energy Proposed 22.40 _ _ _The project was formerly known as the Shell Australia LNG Project and is now called the Arrow Energy LNG

Project.69 Australia Ichthys LNG terminal Inpex Planned 8.40 _ _ _ The project includes Inpex (76%) and Total (24%).

The terminal is expected to be operational by 2016.

70 Australia North West Shelf LNG terminal BHP Billiton Operational 22.82 _ 260,000 4The project includes Woodside Energy Limited (16.67 %), BHP Billiton Petroleum (North West Shelf) Private Limited (16.67 %), BP Developments Australia Private Limited (16.67%), Chevron Australia Private Limited (16.67%), Japan Australia LNG (MIMI) Private Limited (16.67 %) and Shell Development (Australia) Private Limited (16.67 %).

71 Australia Prelude LNG terminal Shell Planned 3.60 _ _ _ Prelude will be a floating facility.

72 Australia Queensland Curtis LNG terminal Queensland Curtis LNG (BG Group) Planned 16.80 _ 600,000 3 The terminal is expected to come online by 2014.

73 Australia Scarborough (Pilbara) LNG terminal

BHP Billiton and Exxon Planned 8.40 _ _ _ The project partners include BHP Billiton (50%) and Exxon (50%) .

74 Australia Sunrise LNG terminal Woodside Proposed 5.60 _ 210,000 _ It is a joint venture of the Woodside (33.44 %), Conoco Phillips (30%), Shell (26.56%) and Osaka Gas (10%).

75 Australia Wheatstone LNG terminal Chevron Planned 8.90 _ _ _ The project partners include Chevron (80%), Apache

(13%) and Kuwait Foreign Petroleum Exploration 76 China Dapeng / Guangdong Guangdong Dapeng LNG Company Limited (CNOOC, BP) Operational 9.38 1,039,133 480,000 3 The terminal is operational since 2008.

77 China Fujian Phase I and II CNOOC Fujian LNG Company Limited (CNOOC) Operational 7.28 395,579 640,000 4 Phase I has been operational since 2007 and Phase II will be operational in 2011.

78 China Shanghai Shanghai LNG Company Limited (CNOOC, Shenergy) Operational 1.54 460,525 200,000 3 The terminal is operational since 2009 and will be expanded by 2012 after which it will receive 4.2 bcm /

79 China Dalian Phase I and II CNPC Under Construction 12.60 460,525 320,000 2 The terminal is expected to be operational by 2011. The Dalian Phase I will have a capacity of 4.2 bcm / year

80 China Rudong / Jiangsu CNPC Under Construction 13.50 531,375 _ 2 The terminal is expected to be operational by 2011.81 China Shenzhen CNPC Planned 3.15 307,017 _ _ _82 China Zhejiang / Ningbo CNOOC Zhejiang Ningbo LNG Company Limited Under Construction 4.20 460,525 _ _ The terminal is expected to be operational by 2012.83 China Zhuhai CNOOC and Yudian Group Under Construction 4.90 466,429 _ _ The terminal is expected to be operational by 2013.84 China Qingdao / Shandong Sinopec and Huaneng Group Under Construction 4.00 460,525 480,000 3 The terminal is expected to be operational by 2013.

85 China Hainan CNOOC and Hainan Development Planned 2.80 307,017 320,000 2 The terminal is expected to be operational by 2014 and expansion in 2017.

86 China Tangshan PetroChina Planned 4.90 531,375 480,000 3 The terminal is expected to be operational by 2013.87 China Beihai Sinopec Proposed 4.20 460,525 960,000 6 The terminal is expected to be operational by 2014.88 China Jiangsu Yancheng CNOOC and Yancheng Municipal Proposed 4.20 460,525 _ _ _89 China Jieyang (Yuedong) CNOOC Planned 2.80 _ _ _ _90 China Tianjin Sinopec Under Construction 4.20 _ _ _ _

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Appendix VI Europe LNG Capacity Country Country Company Status Capacity

(bcm / year)Capacity

(m3 Storage Trains Comments

1 Belgium Zeebrugge Fluxys LNG Operational 9 1,700,000 380,000 4 Capacity expansion and open season in progress2 Croatia Adria LNG Total, Geoplin, E.ON, OMV, Plinacro and HEPProposed 10 to 15 _ _ _ Adria consortium: E.ON Ruhrgas (39.17%), OMV (32.47%), Total (27.36%), Geoplin (1%). Environmental assessment completed. Expected to come online by 20173 Cyprus Vassilikos DEFA Proposed 1 to 1.7 _ _ _ Expected to come online by 20144 France Dunkerque Dunkerque LNG (Electricité de France)Proposed 10 1,400,000 380,000 2 Expected to come online by 2014 Variations can be : 13 bcm/y; 1,900,000 Nm3/h; 570 000 m3 LNG, 3 tanks5 France Fos Cavaou GDF SUEZ Operational 8 1,160,000 330,000 3 _6 France Fos Tonkin GDF SUEZ Operational 6 1,150,000 150,000 3 Open season under way for extending terminal' s commercial operation beyond 20147 France Fos-Sur-Mer GDF SUEZ Proposed 8 1,150,000 360,000 2 Expected to come online by 20168 France Le Havre (Antifer) Gaz de Normandie Proposed 9 1,150,000 510,000 3 Expected to come online by 20159 France Montoir De Bretagne GDF SUEZ Operational 10 1,600,000 360,000 3 Consideration for expansion of capacity from 10.0 bcm/y up to 16.5 bcm/y to be done in 2 phases. In first phase capacity expansion to 12.5bcm/y and is expected to come online by 2011. In second phase capacity expansion to 16.5bcm/year and is expected to come online by 2014.10 France Pegaz 4Gas Proposed 6 800,000 310,000 2 Project rejected unexpectedly by the State in July 2009. 4Gas now trying to sue state to recover investment. Unless state changes its mind this project is abandoned.11 Germany Wilhelmshaven RWE, Excelerate Energy and Nord-West OelleitungProposed 5 _ _ _ Expected to come online beyond 2013.12 Germany Wilhelmshaven DFTG (E.ON) Proposed 11 1,200,000 320,000 2 _13 Germany Rostock Vopak, Gasunie and VNGProposed 2 to 5 _ 150,000-360,000 _ Expected to come online by 2014.14 Greece Kavala Depa and GDF SUEZ Proposed To be Confirmed _ _ _ Co-operation agreement signed mid 2008 - currently deciding whether site should be off or onshore - Depa is performing these surveys. Expected to come online by 2015.15 Greece Revithoussa DESFA Operational 5 750,000 130,000 2 Expected plans for future capacity expansion to 7.4bcm/y, regasification capacity expansion to 990,000 m3 (N)/hour and number of LNG tanks to be increased to 3. Expected to come online by 2015.16 Greece Palei Galini-Iraklion-Crete IslandDESFA Proposed 2 250,000 175,000 1 Expected to come online by 2016.17 Greece Astakos-Navipe Qatar Petroleum Proposed _ _ _ _ _18 Ireland Shannon Shannon LNG (subsidiary of HESS LNG)Proposed 6.5 to 10.8 _ 800,000 4 Expected to come online beyond 2013.19 Italy Panigaglia GNL Italia Operational 2 284,000 100,000 2 Expected plans for future capacity expansion to 3.4bcm/y, regasification capacity expansion to 415,000 m3 (N)/hour. Expected by 2011. Further expansion plans for capacity expansion to 7.6bcm/y, regasification capacity expansion to 916,000 m3 (N)/hour and LNG storage capacity to be increase to 240,000 m3. Expected by 2017.20 Italy Porto Levante Adriatic LNG Operational 8 1,100,000 250,000 2 _21 Italy Toscana Offshore OLT, Endesa, E.ON and IrideUnder Construction 4 _ 137,000 _ Expected to come online by 2011.22 Italy Brindisi British Gas Italia Proposed 8 _ 320,000 2 _23 Italy Taranto Gas Natural InternacionalProposed 8 _ 300,000 2 _24 Italy Senigaglia / Ancona (Offshore)GDF SUEZ Proposed 5 _ _ _ _25 Italy Gioia Tauro LNG MedGas Terminal Proposed 12 _ _ _ Expected to come online by 2014.26 Italy Rada Di Augusta-Priolo Shell Energy Italia and ERG Power & GasProposed 8 _ _ _ _27 Italy Porto Empedocle Nuove Energie Srl (ENEL 90%)Proposed 8 _ _ _ Expected to come online by 2014.28 Italy Rosignano (Offshore) Edison, BP and Solvay Proposed 8 _ _ 1 _29 Italy Ravenna (Offshore) Atlas Ing (Gruppo Bellini)Proposed 8 _ _ _ _30 Italy Trieste (Offshore) Endesa Europa Proposed 8 _ _ _ _31 Italy Zaule Gas Natural InternacionalProposed 8 _ 300,000 2 Expected to come online beyond 2014.32 Poland Swinoujscie Polskie LNG Sp. z o.o. and Gaz-SystemProposed 5 to 7.5 656,000 320,000 2 Expected to come online by 2014.33 Portugal Sines REN Atlantico Operational 6 900,000 240,000 2 Expected plans for future capacity expansion to 8.3bcm/y, regasification capacity expansion to 1,350,000 m3 (N)/hour and number of lng tanks to be increased to 3. Expected to come online by 2012.34 Spain Barcelona Enagas Operational 17 1,950,000 540,000 6 Expected plans for future lng storage capacity to be increased to 680,000 cubic metres and number of lng tanks to come down to 5. Expected to come online by 2011. 35 Spain Bilbao Bahia de Bizkaia (BBG)Operational 7 800,000 300,000 2 Expected plans for future capacity expansion to 12.3 bcm, regasification capacity expansion to 1,400,000 m3 (N)/hour and number of lng tanks to be increased to 4. Expected to come online by 2011.36 Spain Cartagena Enagas Operational 11 1,350,000 437,000 4 Expected plans for future capacity expansion to 14.5 bcm per year, regasification capacity being expanded to 1,650,000 m3 (N)/hour and number of lng tanks to be increased to 5. Expected to come online by 2014.37 Spain Musel Enagas Under Construction 7 800,000 300,000 2 Expected plans for future capacity expansion to 10.5 bcm, regasification capacity expansion to 1200,000 m3 (N)/hour and number of lng tanks to be increased to 4. Expected to come online by 2011.38 Spain Gran Canaria (Arinaga) Gascan Under Construction 1 150,000 150,000 1 Expected to come online by 2013. Expected plans for future capacity expansion to 2 bcm, regasification capacity expansion to 225,000 m3 (N)/hour and number of lng tanks to be increased to 2. Expected to come online by 2014.39 Spain Huelva Enagas Operational 12 1,350,000 460,000 4 Expected plans for capacity expansion to 15.8 bcm per year, regasification capacity being expanded to 1,800,000 m3 (N)/hour and number of lng tanks to be increased to 6. Expected to come online by 2015.40 Spain El Ferrol Reganosa Operational 4 413,000 300,000 2 Expected plans for capacity expansion to 7.3 bcm and regasification capacity being expanded to 825,600 m3 (N)/hour. Expected to come online by 2013. Project partners are Endesa 21%, UFG (21%), Sonatrach (10%) and various institutional investors41 Spain Sagunto Saggas Operational 9 1,000,000 450,000 3 Expected plans for future capacity expansion to 14 bcm, regasification capacity expansion to 1,600,000 m3 (N)/hour and number of lng tanks to be increased to 5. Expected to come online by 2014. Saggas shareholders are Union Fenosa Gas, Iberdrola, Endesa and Oman Oil Partners 42 Spain Tenerife (Arico-Granadilla) Gascan Under Construction 1 150,000 150,000 1 Expected to come online by 2012. Expected plans for future capacity expansion to 2 bcm, regasification capacity expansion to 225,000 m3 (N)/hour and lng storage capacity expansion to 300,000 m3. Number of lng tanks to be increased to 2. Expected to come online by 2016.43 The Netherlands Gate Terminal Gasunie and Vopak Under Construction 12 1,650,000 540,000 3 Expected to come online by 2011. Expected plans for future capacity expansion to 16bcm/y, regasification capacity expansion to 2,200,000 m3 (N)/hour and number of LNG tanks to be increased to 4. Expected to come online by 2014/2015.44 The Netherlands Eeemshaven LNG Essent, Gasunie and VopakProposed 12 1,300,000 360,000 2 Expected to come online by 2015.45 The Netherlands Liongas 4Gas Abandoned 9 1,050,000 _ _ 4Gas BV concluded that in the near future there is not sufficient commercial and financial support in the market for the LNG terminal, in any form whatsoever. On this basis, 4Gas BV and the Port Authority decided to cancel the project LionGas.46 United Kingdom Teesside, Middlesbrough Norsea Pipeline Ltd Proposed 20 _ _ _ _47 United Kingdom Gateway LNG Stagenergy Proposed _ _ _ _ _48 United Kingdom Isle Of Grain National Grid Operational 13 1,750,000 770,000 7 Expected plans for future capacity expansion to 19.5 bcm, regasification capacity expansion to 2,650,000 m3 (N)/hour, lng storage capacity expansion to 970,000 m3 and number of LNG tanks to be increased to 8. Expected to come online by 2011.49 United KingdomMilford Haven (South Hook LNG)ExxonMobil, Qatar Petroleum and TotalOperational 21 2,440,000 775,000 5 _50 United KingdomMilford Haven (Dragon LNG)BG, Petronas and 4GasOperational 6 1,140,000 320,000 2 _51 United Kingdom Anglesey Canatxx Proposed 31 3,542,500 _ _ _52 United Kingdom Canvey Island Calor Gas Proposed 5 _ 240,000 2 _

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Appendix VII Map Leviathan – Block 12