In this issue:

1 Global LNG trade dynamics undergo changes in shipping and supply sidesLNG Journal, Europe Editor

5 Japan’s LNG demand may soar higher if price and infrastructure issues are tackledNaoto Nakamura, Osaka Gas, Osaka, Japan

8 A round-up of latestevents, company andindustry news News index

18 Floating LNG’s time has come as Prelude project offshore Australia gets investmentLNG Journal, Asia-Pacific Editor

20 FLNG technical challenges addressed as Shell reveals game plan for stranded gasBarend Pek, General Manager LNG Front End Development, Shell Projects and Technology

24 Dual-enhanced tubes prove durable and stable performers for LNG processingThomas Lang, Wieland-Werke AG, Ulm, Germany, and Brigitte Ploix, Technip, Paris, France

26 World Carrier Fleet:Details of LNG vessels

32 Tables of import and export LNG terminalsand plants worldwide

June 2011

36 pagesessential LNG

news!

Global LNG trade dynamics undergochanges in shipping and supply sidesThe global LNG market is currently re-

aligning under the effects of increased

requirements for incremental LNG

cargoes in Japan as project developers

push ahead and more countries become

importers.

The number of spot and short-term

LNG cargoes grew to more than 700

cargoes last year and that figure is set to

grow even more with the surge in short-

term LNG to Japan.

Japan may require up to 15 million

tonnes per annum of additional short-

term LNG imports in 2012 because of the

nuclear power generation cuts caused by

the March earthquake.

ExpansionBy the end of this year Japanese utilities

will have imported more than 11 MT of

additional LNG in the form of

supplementary supplies of spot cargoes

or cargo swaps, according to latest

estimates.

Prices of short-term LNG cargoes for

Japan in early June 2011 were at around

$13.50 per million British thermal units.

In the meantime, countries as diverse

as Kenya in East Africa and the Baltic

state of Lithuania are among the latest

nations to be developing LNG import

facilities and seeking suppliers.

The France-based International Group

of Liquefied Natural Gas Importers

(GIIGNL) has also published its annual

report noting the latest trends in the

industry.

That’s as the LNG carrier fleet

worldwide emerges from a three-year

slump and vessel owners cash in on

demand for shipping for spot cargoes that

has reached rates of more than $90,000 a

day or more from under $40,000 in 2010.

Cargo flowsThe LNG carrier fleet has also grown to

more than 360 ships in 2011, with more

than 30 others on order.

Due to the decline of indigenous

production in mature markets and the

development of new gas markets,

international gas flows continued to

expand, and total international gas trade

increased by 10.9 percent last year

compared with the previous year, the

report from the importer group said.

“In this context, LNG flows recorded

the largest growth with a 21 percent

increase, the operational start-up of new

liquefaction capacity in Qatar being the

primary reason. By comparison, pipeline

trade increased by 7 percent,” it added.

RecoverySpurred by global economic recovery, this

record increase was allowed by the rise of

production levels from existing facilities

in Qatar, Nigeria, Indonesia and Russia,

as well as by the addition of new

liquefaction capacity in Qatar, Yemen

and Peru.

On the import side, Asian LNG

markets experienced a strong recovery,

up 16.8 percent after a 4 percent decline

in 2009.

European imports continued to grow

by 24.8 percent, with the majority of

additional volumes coming from Qatar

and being delivered into three countries:

Italy (Rovigo), the UK (South Hook) and

Turkey (Aliaga).

Imports into Central and South

America more than doubled because of

new players such as Argentina, Brazil

and Chile.

At the end of the year, Japan remained

the leading LNG importer on 70.87 MT,

with South Korea on 32.64 MT. Korea’s

share of all imports reached 14.8 percent.

Japan’s import total is likely to surge

over 80 MT in 2011 because of

requirements after the March disaster.

The UK is rapidly catching Spain as

Europe’s largest importer. Spanish

imports for 2010 were just over 20 MT

and the UK was at just over 14 MT, with

France in third at 10.4 MT.

Spain was still the third-largest of all

importers, with 9.5 percent of global

supply, halting an 8 percent decline in

imports in the previous year because of

the economic downturn.

India was the only Asian customer last

year to reduce its appetite for LNG, as a

result of growing domestic production,

though still importing just under 9 MT.

In the Americas, due to the rise of non-

conventional domestic gas supplies, and

to the low-price environment, LNG

imports to the US declined to around

8 MT last year after netting out LNG

re-exports.

AppetiteIn contrast, the appetite for LNG in

South America grew strongly, mainly as

a result of gas demand for power

generation.

Imports by Argentina, Brazil and

Chile almost tripled compared with the

previous year to more than 5.5 MT,

LNG Journal, Europe Editor

LNG trade is booming worldwide and 2011 will see volumes climb higher

p1-7:LNG 3 17/06/2011 09:31 Page 1

eight from Sabine Pass in Louisiana and

four from Freeport LNG in Texas). Nine

of these were re-exported east of the Suez

Canal and 10 remained in the Atlantic

Basin.

FlexibilityAs an illustration of the growing global

flexibility of LNG cargoes, it was noted

that three LNG cargoes re-exported from

the US ended up in the UK, India and

South Korea in January 2011.

As to the sourcing of spot and short-

term trades in 2010, Qatar overtook

Trinidad and came first with a 25.7

percent share, followed by Trinidad (17.2

percent), Nigeria (12.3 percent) and

Egypt (7.3 percent).

In 2010, new flexible volumes from

Qatar contributed to 45.3 percent of the

new spot and short-term volumes on the

market, followed by Nigeria at 18.8

percent and Yemen on 12.6 percent.

Other facts disclosed by the trade body

percent of the world LNG trade.

LNG traded under long-term contracts

recorded a 17 percent increase. The rise

of spot and short-term operations was

particularly significant in Europe, up

more than 50 percent because of

attractive prices and the availability of

uncommitted LNG supply from the

Middle East.

After a sharp decline in 2009, Asia also

experienced a renewed growth in spot

and short-term purchases in 2010 and

the figure is expected to be even higher

by the end of 2011 because of Japan’s

imports.

Spot and short-term trading of LNG

last year was also marked by the growing

activity of non-asset-based players,

including financial institutions and oil

trading companies, as well as by the

significant number of re-exported

cargoes, the report said.

Also during 2010 a total of 19 cargoes

were reloaded (seven from Zeebrugge,

2 • LNG journal • The World’s Leading LNG publication

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journal

The World’s Leading LNG publication

giving them a 2.6 percent share of global

supplies and more than the imports of

around 4.3 MT made by established

importer Mexico.

On the export side, the GIIGNL report

said LNG output grew to just over 220

MT. In addition to production build-up of

facilities commissioned in 2009 there was

also some enhanced operational

performances from existing Trains.

On a regional basis, exports from the

Pacific Basin grew by 15.1 percent,

allowing the region to remain the major

source of LNG exports with 83.2 MT,

compared with 75.6 MT from the Middle

East and 61.3 MT from the Atlantic

Basin.

Nevertheless, the Pacific Basin’s share

of world LNG exports went down from

39.5 percent in 2009 to 37.2 percent in

2010.

MideastDue to Qatar’s new Trains, the Middle

East contributed 33.9 percent of world

exports of LNG compared with 27.9

percent in the previous year.

The Atlantic Basin’s share of global

production was reduced to 28.8 percent

from 32.5 percent the previous year due

to the reduction of exports from North

Africa.

Production was boosted by countries

such as Qatar, Nigeria, Russia and

Indonesia, while production fell in Egypt,

Algeria and Trinidad.

The Egyptians saw their LNG

deliveries drop more than 30 percent due

to the growth of the country’s domestic

gas needs, the report added.

During 2010, Qatar was responsible

for one quarter of global LNG production,

exporting to all countries with import

facilities except for Greece, Kuwait,

Puerto Rico and the Dominican Republic.

Indonesia returnLast year also saw the return of

Indonesia to second in the ranks of LNG

producers, after briefly falling behind

Malaysia. Fourth-ranked was Australia,

followed by Nigeria.

Nigerian exports rose by 54.2 percent

to 18 MT due to restored gas supplies to

the Bonny island LNG plant following

the restart of the Soku facility, Nigeria’s

key feeder gas plant.

Spot and short-term imports, defined

as contracts with a duration of four

years or less, recorded a very strong

increase of 40 percent and reached 727

cargoes in 2010 compared with 491

cargoes in 2009, accounting for 18.9

Global imports of LNG are growing as the production volumes increase

p1-7:LNG 3 17/06/2011 09:32 Page 2

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4 • LNG journal • The World’s Leading LNG publication

LNG MARKET

showed that world LNG trading involved

149 “flows” (i.e. country-to-country

trades) over 386 sea transportation

routes (port-to-port routes). Of the total

100 routes were new.

RoutesIn 2010, there were 42 new country-to-

country flows: Abu-Dhabi to Brazil,

China, Korea, Kuwait, Spain and Taiwan;

Algeria to Chile and Japan; Egypt to

Belgium, Chile and Kuwait; Equatorial

Guinea to Greece, India, Italy and

Kuwait; Nigeria to Kuwait and the UK;

Norway to Belgium, Italy, Korea and

Taiwan; Peru to Belgium, Brazil, Canada,

Korea, Mexico, Spain and the US; Qatar

to Argentina, Brazil, Dubai and Portugal;

Trinidad to Chile and Italy; Yemen to

Chile, China, France, India, Japan,

Kuwait, the UK and the US.

At the end of December 2010, the

number of LNG carriers under

construction or on firm order was 20, of

which two will have Moss tanks and the

18 others the GTT membrane tank.

Then, in the first two quarters of 2011

there were a dozen more orders placed for

new-builds at Korean shipyards.

In 2010, LNG traffic towards Europe

via the Suez Canal soared, with a 74

percent increase compared with the

previous year, the report said.

This can be explained by the addition

of new imports from the Middle East and

by the 30 percent discount on official

transit rates granted by Egypt following

Qatar’s request.

By way of comparison, the traffic of

loaded oil tankers via the Suez Canal

only recorded a 1.8 percent increase.

LiquefactionThere were 25 LNG liquefaction facilities

in operation in 18 countries at the end of

2010. There were 94 liquefaction Trains,

with the average utilization rate reaching

81 percent, compared with 74 percent the

previous year. Utilization numbers have

since grown during 2011.

At the Bonny Island liquefaction

plant, the Nigeria LNG joint venture is

currently planning the construction of a

seventh treatment unit, which is

expected to come on line by 2013.

Regarding the Brass LNG project in

Nigeria, front-end engineering operations

were proceeding and the final investment

decision is expected in the first quarter of

2012. The plant is expected to be

completed in 2015 and it could produce

up to 10 MTPA.

There were 83 LNG regasification

terminals in operation at the end of 2010,

including 10 floating facilities. The total

send-out capacity of the facilities in

operation amounted to 600 MTPA (796

Bcm of gas) compared with annual LNG

consumption of 220 MTPA.

UtilizationThe global average utilization rate of

installations was around 37 percent last

year.

The annual average utilization rate of

regasification terminals is characterized

by significant regional discrepancies:

very low in North America (about 12

percent) due to the unforeseen

development of shale gas.

However, regasification use reaches 42

percent in Asia and 50 percent in Europe,

with intra-annual peaks according to the

seasonal variations in demand.

There were most notably start-ups,

expansions and upgrades of LNG import

terminals in China.

At the Dapeng terminal, the design

was completed for the fifth loading arm,

and a new nitrogen generation facility

was being installed and commissioned.

Regasification capacity per annum is now

around 9 Bcm.

InvestorsKunlun Energy, a Hong Kong subsidiary

of CNPC, secured a 75 percent stake in

the Petrochina Dalian LNG company, the

operator of the Dalian LNG terminal in

China’s Northeastern Lioning province.

The other shareholders of PetroChina

Dalian LNG are Dalian Port (20 percent)

and Dalian Construction Investments (5

percent).

The company completed the

construction of a wharf capable of

receiving Q-Flex LNG tankers, which will

be the first phase of the 3 MTPA project.

A second step which may double the

terminal capacity is planned later. LNG

will come from Qatar and Australia.

PetroChina’s Rudong LNG terminal in

China’s Eastern province of Jiangsu

received its first cargo from Qatargas

in 2011.

PetroChina has a 25-year supply

contract with the Qatargas IV plant for

3 MTPA.

At the same time Sinopec has begun

construction of its Qingdao LNG terminal

project in the eastern province of

Shandong.

That project is scheduled to start up in

2014 with an initial import capacity of 3

MTPA, increasing to 6 MTPA.

The company signed a 20-year supply

contract with ExxonMobil for 2

MTPA from the PNG LNG

project in Papua New

Guinea.

Additionally,

CNOOC has

started

construction

at its Zhuhai

terminal, its

second

terminal in

the southern

province of

Guandgdong

after Dapeng.

The initial

capacity of 3.5 MTPA

could be expanded to 12

MTPA. The terminal will

receive LNG supplies from CNOOC’s

long-term contracts with Qatargas and

BG’s Queensland Curtis CSG-to-LNG

project in Australia.

In India, Petronet LNG has started

building a second jetty at the Dahej

terminal to handle larger capacity LNG

carriers. The company is also studying

plans to build two additional storage

tanks to increase terminal capacity.

The new LNG terminal in Kochi

(Petronet) is expected to be commissioned

at full capacity of 5 MTPA by March

2012.

At the Dabhol LNG terminal located

in Maharashtra (South West of India)

and operated by Ratnagiri Gas and

Power, operations have been delayed due

to the lack of breakwater which would

only be completed this year.

Full capacity will be around 5 MTPA

and three 160,000 cubic metres storage

tanks will be built.

New projectConstruction of a 6.5 MTPA receiving

terminal is planned at Mundra in

Gujarat, India. FEED has been

completed and land reclamation activity

is in progress.

In South Korea, the expansion of the

1.7 MTPA LNG receiving terminal in

Gwangyang (Posco) was completed with

the addition of a third above-ground

storage tank (165,000 cubic metres).

Another significant report released in

early June 2011 came from the

International Energy Agency.

According to the IEA, there is a

“dramatic and continuing expansion of

LNG trade” around the world and the

trade in natural gas between regions

will double to over 1 trillion cubic metres

by 2035.

In the

IEA’s

new

“Gas

Scenario”

report, the

surge in demand for

LNG, shale-gas and pipeline gas is driven

by: mounting worries over energy security

and climate change, the renewed debate

surrounding nuclear power, the North

American shale-gas boom, and more

significantly, lower gas prices.

Rapid growthGas will overtake coal before 2030 and

meet one quarter of global energy

demand by 2035, the IEA said. Demand

will grow by 2 percent annually,

compared with just 1.2 percent for total

energy, the report added.

“The LNG industry is in the midst of

rapid expansion, which is boosting

significantly the share of LNG in global

gas trade,” the IEA said.

Australia is singled out as a major

future producer of LNG from its 4.6

trillion cubic metres reserves of

conventional gas and 420 Bcm of CSG.

“The potential CSG resource is

considerably larger, possibly 10 times this

amount,” the IEA said.

“Moreover, much of the land mass and

large offshore areas have yet to be fully

explored,” the report said.

While Russia, Nigeria and Iran still

had huge potential for LNG and other

gas projects, no final investment

decisions were imminent from those

countries, the IEA report added.

“Australia is set to become the key

LNG supplier in the next decade, but

controlling costs (of projects) will be an

ongoing challenge,” the IEA said.

An increase in global gas production

equivalent to three times what is

produced now by Russia will be required

to meet the growth in gas demand by

2035, the IEA stated. �

“The LNG industry is in the midst of rapid

expansion, which isboosting significantly

the share of LNG in global gas trade”

p1-7:LNG 3 17/06/2011 09:32 Page 4

LNG PRICING

LNG journal • June 2011 • 5

It was more than 40 years ago that LNG

was first introduced to Japan. Even

before the March disaster, the Japanese

government in its revised “Basic Energy

Plan” had positioned LNG as the core

energy source in the country’s supply mix

over the long term.

Based on this shift in its energy policy,

the government will expand LNG use

while drastically reducing emissions of

greenhouse gases. Japan will maintain

its leadership position as an importer in

the world LNG industry.

Now, the first question that may be

raised is whether LNG would be a bridging

energy or would it continue to be a core

energy source for Japan and for Asia.

QuestionsWhen oil prices are again high at over

$100 per barrel, I have to question

whether it is viable for LNG to be price-

indexed to crude oil in Asia when it does

not reflect the circumstances of the

current market.

When considering oil-indexed LNG

one must examine the S-curve pricing

mechanism, and its role in the past and

in the future in expanding demand for

LNG in Japan.

I believe that an effective pricing

formula that enables the growth of the

Japanese LNG market would also help to

realize an expansion of LNG demand in

Asia as a whole.

As a result, both producers and

consumers would be able to enjoy a

continuous growth of their businesses.

This, I believe, would achieve a win/win

result for all parties in the LNG industry.

Reviewing the drastic energy price

fluctuations during the past few years

and their implications on the Japanese

LNG market, Figure 1 shows the price

trends of the Japanese Crude Cocktail

(JCC) and the Japanese LNG Cocktail

(JLC) after 2003 in which their average

prices are compared on the thermal

equivalent basis per ton of LNG.

InstabilityWe see here that the JCC started to rise

after 2004 and surged in 2007. After

these changes, JCC prices dropped

drastically in the latter half of 2008.

The JLC, on the other hand, with some

time lag compared with the JCC, shows

similar price trends, indicating a strong

price linkage between the two.

Looking at the fluctuation levels,

however, the JCC fluctuated by 4.3 times

and the JLC by 2.8 times.

The smaller fluctuation range of the JLC

is an effect of the S-curve pricing

mechanism adopted in many price formulas.

When it was first introduced to Japan,

LNG was viewed as a substitute for oil,

particularly for power generation.

Because of this, a pricing formula

indexed to the JCC was adopted in many

LNG projects for Japan.

During the mid-1990s when crude oil

prices were stagnating, a new LNG pricing

formula was introduced for the purpose

of moderating the level of LNG price

decline when crude oil prices dropped.

S-CurveCalled the S-curve, the formula was

designed to moderate LNG price rises

when oil prices were increasing.

This mechanism, therefore, relieved

producers of the price impacts when oil

prices were low and it also eased the high

price pressures for buyers.

The formula has also realized benefits

of stabilizing the price of LNG compared

with crude oil. Further, when combined

with a benefit of stable supply by

pipelines in Japan, LNG could enjoy

added value of higher stability of price

compared with its competing fuels.

Turning to surging energy prices, there

are various effects energy price spikes

have had on the gas demand in Japan.

Fuel switchFirstly is the accelerated fuel switch

from oil to natural gas in the industrial

sector because of higher price

competitiveness of gas against oil.

Secondly, the economic recovery with

its strong appetite for capital investment,

and higher environmental consciousness,

boosted the demand for gas.

Thirdly, despite boosted gas demand

due to fuel switching, gas equipment such

as cogeneration systems that compete

with electricity, experienced a decline in

their competitiveness, discouraging their

market expansion.

The energy price fluctuations and the

subsequent decline in demand in the

market could be summarized in the

following three points:

1. Increased energy costs pressured

profits of businesses, and when

coupled with the global economic

recession, demand for natural gas

experienced a temporary decline.

2. An increasing number of industrial

customers took various actions due to

uncertainty in their business outlook,

including business down-scaling,

integrating and transferring overseas

their production activities. This trend

reflected their difficulty in making

tough decisions on capital investment

which require long pay-back time, and

it slowed down the pace of fuel

switching.

3. After experiencing price fluctuations,

though smaller in their ranges than

oil, natural gas suffered a reputation

damage of its ‘price stability’ which

was its major selling point.

As I have described, natural gas

experienced a temporary boost in its

demand when oil price surged, but it

later had a negative impact on Japanese

gas customers for its price uncertainty.

While we are currently experiencing

gradual price increases of crude oil,

customers in Japan have serious concerns

over possible spikes of energy prices.

Such uncertainty on the part of energy

users has been at the root of the failure of

gas demand to increase substantially,

despite general economic recovery in

Japan.

Industrial useThere are two major uses for natural

gas in Japan, power generation and gas

distribution. When Japan started

imports of LNG, it was used mostly

for power generation. During the last

20 years, LNG demand for gas

distribution has grown fast and now it

accounts for 40 percent against 60

percent for power generation.

Looking at the trend of gas demand for

industrial uses, it accounted for 50

percent of total gas demand in the gas

distribution market in the country, which

was 18 billion cubic metres or 15 million

tonnes of LNG.

When LNG was first introduced,

industrial consumption stood at mere 500

million cubic metres, or 11 percent of

total gas demand in a given year.

The impressive growth of natural gas

demand for industry has been made

possible by the higher environmental

advantages and the expanded use of

natural gas for advanced gas utilization

such as cogeneration.

Looking at the economics of natural

gas compared with oil, end-use gas prices

have additional cost elements such as

pipeline transmission and distribution

and safety costs at customers’ premises.

CostlyThe higher fuel cost of natural gas makes

it more costly for manufacturers to

convert to gas from oil.

The price of gas, however, becomes

more affordable when combined with the

installation of energy-saving equipment

such as cogeneration systems, which

minimize utility bills including grid

electricity charges.

According to the “Basic Energy Plan”

adopted last year, “promotion of fuel shift

to natural gas” aims to double the

proportion of natural gas in the

industrial sector from recent levels by

2030 as part of the government’s

measures against global warming.

Japan’s LNG demand may soar higher if price and infrastructure issues are tackledNaoto Nakamura, Osaka Gas, Osaka, Japan

Figure 1: Close linkage between Japan Crude Cocktail and Japan LNG Cocktail

p1-7:LNG 3 17/06/2011 09:32 Page 5

LNG PRICING

6 • LNG journal • The World’s Leading LNG publication

Based on this goal, it forecasts a 25

percent increase in gas demand from

Japanese gas utility businesses in the

next 20 years.

The Plan also sets forth a target of 50

percent increase of cogeneration capacity

up to 8 gigawatts by 2020, and it will

more than double to 11 GW by 2030.

Core fuelThe Plan therefore, foresees a future

energy situation in Japan in which

natural gas is positioned as a core energy

source to realize a low-carbon society in

20 years.

The Plan recognizes cogeneration

systems as the most effective means to

achieve the goals of reducing CO2 emission.

To ensure the growth of the LNG in

the market, it will be important to

achieve further development of the

mature Japanese gas industry.

For this purpose, it is essential to realize

growth of gas demand through cogen-

eration in the industrial sector which has

been positioned as an effective instrument

in achieving a low-carbon society.

To do so, economical and stable gas

pricing must be realized.

The advantage of cogeneration

systems on the basis of running costs

depends largely on differences between

gas and electricity rates.

In the case of electricity rates in

Japan, power companies reflect

proportionally the price fluctuations of

thermal fuels such as coal, oil and LNG

in their portfolio of fuels for electricity.

Hydro and nuclear are not subject to

the same price fluctuations as thermal

fuels, whose costs are linked to the

LNG price.

This means that, when fuel prices get

higher, the price competitiveness of

cogeneration becomes smaller. The

advantages of cogeneration in its running

cost changes according to the LNG price.

When a slope of an LNG pricing

formula is placed at 14.85, which is said

to be a traditional slope, economic

advantages of a 7 megawatts turbine-

driven system is halved as the JCC

price increases from $40 to $70, and

it is reduced to 1/10 when the JCC is

at $100.

With such a calculation, it would be

difficult to depreciate the capital cost of

the cogeneration systems, let alone

realize an expansion of cogeneration in

the energy market.

Conversely, to realize the original

economic advantages of cogeneration, it

has been calculated that a slope of LNG

pricing should be less than 8.

I calculated a relationship between the

JCC and the payback years for a

cogeneration system based on existing

electricity and gas prices. (See Figure 2)

The payback time gets much longer

when the JCC goes beyond the $60 to

$70 range. However, the current JCC

price level goes far beyond the upper

limit for promoting cogeneration

systems in Japan.

If we are to realize continued

expansion of natural gas in the industrial

energy supply, it will become necessary

to control the price linkage between LNG

and oil in the high price ranges of oil.

It should prove effective, therefore, to

introduce the S-curve in the LNG pricing

formula for the purpose of moderating a

slope in the high price range of oil.

Furthermore, the S-curve could be a

step forward to move away from the

crude oil-linked pricing formula to realize

a truly competitive pricing for LNG.

Another element which requires price

stability for natural gas is developing

pipeline infrastructure for ensuring

growth of gas in the industrial sector.

ConcentrationPipeline networks in Japan are

fragmented and they are only established

to serve major economic regions,

centering on Tokyo, Osaka, and Nagoya.

This means that gas demand is

concentrated in those regions where

industrial gas for thermal applications

has seen high market saturation. In the

case of Osaka Gas, natural gas accounts

for about 80 percent of the heat demand

in this sector. This means that more

potential industrial gas demand is

located in those places outside the reach

of the pipeline network.

InfrastructureIt is therefore essential to improve

pipeline infrastructure in the country.

Enormous investments for pipeline

construction must be recovered through

the continued growth of gas demand over

the long term.

Assuming industrial heat demand,

excluding that of coal, is met by natural

gas in the whole service area of Osaka

Gas, it would be equivalent to 30 million

tonnes of additional LNG demand.

In order to achieve sustainable

growth of the LNG industry in Japan,

potential demand needs to be cultivated

and the necessary infrastructure has to

be developed.

Japan has even more significant

growth potential for LNG because of the

country’s positioning of natural gas as a

key energy source towards a low-carbon

society.

CriticalIn order to realize more growth of

LNG demand, two points are of critical

importance. One is greater expansion

of cogeneration systems in the country,

and the other is to develop pipeline

networks beyond the existing geographic

locations.

To achieve these objectives, price stability

of natural gas needs to be enhanced at

the time of rising oil prices, and thereby

maintaining its price competitiveness.

To improve price competitiveness of

LNG indexed to crude oil, I believe an

effective solution would be to revive a

price formula with the S-curve.

Looking at the overall Asian market,

Figure 2: Changes in the JCC and their impact on the payback time forcogeneration systems. A JCC of $60 and higher extends the payback time

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LNG PRICING

LNG journal • June 2011 • 7

LNG is expected to replace coal rather

than fuel oil. This is because of fuel

switching for power generation from coal

to natural gas in these countries over the

short to medium term.

Such a development

makes a striking contrast

with Japan where LNG was

first introduced as an

alternative fuel for oil.

PotentialIt is true that there exists

tremendous potential

demand for natural gas in

Asia. There are doubts,

however, about such a

growth possibility under

the current price trends of

oil at $100 per barrel to

which LNG price is indexed.

Price increases of LNG

would significantly affect

the demand for natural gas

in the Asian economies.

Also in looking at the

demand in China and India,

the influence of their

domestic gas should not be

neglected.

By drawing an example

from Japan, it should prove

important to develop gas

demand for manufacturing

industries through

construction of pipelines to

achieve long-term and

stable development of the

LNG industry in Asia.

LNG pricing is an

important element in

ensuring such growth, and

if it is unfavourable, it may

affect the necessary

advances in market

development.

Asian driverThe growth of gas demand

in Asia may also affect the

world LNG industry which

relies on Asia as a driver for

business development.

Difficulties in developing

new projects may hinder

the industry and endanger

the soundness of the

market.

To realize a sustainable

growth of the LNG industry,

it is essential to achieve a

cycle for growth in the LNG

chain; growth in demand to

enable new LNG projects for stimulating

growth of the entire sector, which in turn

would enhance price competitiveness

of LNG.

Viewing the entire LNG industry

from a perspective of achieving growth

in the future, it should become necessary

to weaken the linkage of the Asian

LNG price with oil. I believe

incorporating the S-curve in the pricing

mechanism is a positive step forward to

achieving this objective. �

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p1-7:LNG 3 17/06/2011 09:32 Page 7

8 • LNG journal • The World’s Leading LNG publication

NEWS

ABS, the American Bureau of Shipping

classification society, released at the Nor-

Shipping conference in the Norwegian

capital Oslo a guide on the benefits of

LNG as fuel for ships. The ABS said its

“Guide for Propulsion And Auxiliary

Systems For Gas Fuelled Ships” was

published in response to the industry’s

need for technical guidance for new

construction and existing vessel

conversion. The ABS said it considered

the publication “to be the most

comprehensive available to the industry”

and provides criteria for the

arrangements, construction, installation

and operation of machinery components

and systems for vessels fuelled by

natural gas. The objective of the guidance

is to minimize operating risks and

promote the protection of the vessel, its

crew and the environment, the ABS said.

Christopher J. Wiernicki, ABS Chief

Executive and President said that the

shipping industry needed to examine the

issues surrounding the transition from

traditional fuels to LNG, to verify that

solutions provide an equivalent level of

safety and reliability to those established

for LNG storage and transportation.

“With ship operators facing economic

pressures from fuel costs combined with

impending regulations aimed at reducing

exhaust gas emissions, particularly for

sulfur oxide (SOx), LNG fueled

propulsion systems could be a practical

and beneficial solution. It is a matter of

when, not if, LNG will be a commonly-

selected fuel source and we need a sound

basis for ship designs,” said Wiernicki.

More than 50 years of ABS’s experience

with the handling and storage of LNG on

board ships, many with dual-fuel diesel

propulsion plants was incorporated into

the Guide, it said. Consideration was also

given to industry standards including the

IMO Resolution MSC.285(86) Interim

Guidelines on Safety for Natural Gas-

Fuelled Engine Installations in Ships, the

International Gas Carrier Code and the

IMO International Code of Safety for

Gas-Fuelled Ships, currently under

development. Significant contributions to

the Guide also came from a joint research

project with South Korea’s Daewoo

Shipbuilding and Marine Engineering

and AP Moller Maersk to develop an

LNG-fuelled containership. Concluded

earlier this year, the project addressed

the design and technical issues

surrounding the use of a 7,000 TEU

containership burning LNG as fuel for

both propulsion and power generation,

with ABS providing Approval in Principle

for the resulting design. The study also

assessed operational, economic and

regulatory impacts from the use of LNG

as a fuel source. Results from the study

were presented by DSME in March

during industry’s premiere gas

conference, Gastech, in Amsterdam.

“Natural gas has been used as a fuel for

small regional non-LNG carriers working

in environmentally sensitive areas,” said

ABS Director, Environmental Technology

Yoshi Ozaki who led ABS’s involvement

in the project. “This study further

supports technical feasibility of LNG fuel

and suggests promise for a viable

extended business line for LNG

suppliers,” Ozaki said.

AP Møller-Mærsk, the Danish shipping-

to-oil group, said it planned to “divest” its

Maersk LNG subsidiary comprising eight

LNG carriers just as the LNG shipping

sector emerges from a three-year slump.

The company, the world’s leading owner

of container ships, announced the sale of

Maersk LNG as it said first-quarter

profits for its overall business rose by 82

percent in dollar terms to $1.1 billion

from $639 million in the same period a

year ago. Maersk LNG, which is part of

the division including floating oil

production vessels (FPSOs), returned

profits of $12M for the quarter compared

with a $72M loss in the first quarter of

last year. However, the group said in its

statement it was “going to the market to

find a potential buyer for Maersk LNG”

as the group wishes to reallocate

resources. “The business has seen

successful turnaround in the course of

2010, and is expected to generate profits

and considerable cash flows in 2011 and

the coming years,” the statement said.

“The LNG market experienced increasing

activity in the first quarter 2011 and all

the group’s vessels were fully employed

throughout the period. Maersk LNG

signed contracts in the first quarter of

2011 with a positive impact for 2011 and

2012,” the company added. The LNG

shipping sector has recovered in 2011

and the Danish company is likely to have

no problems finding a buyer for its ships,

analysts said. Maersk LNG took delivery

of its newest LNG carrier, the “Maersk

Meridian” in January 2010, which

brought its fleet numbers to eight vessels.

The “Maersk Meridian” was the last in a

series of six 165,500 cubic metres

capacity dual-fuel electric propulsion

ships from the Samsung Heavy

Industries yard in South Korea,

including the “Maersk Ras Laffan”. The

two other vessels in the LNG fleet have

steam propulsion. There are 12 business

units in the Maersk Group, including

Maersk LNG, and Group Chief Executive

Nils S. Andersen said he was still

confident in “ the long-term future of our

markets and not least our ability to

continue to compete successfully.”

BG Group signed a sales and purchase

agreement with Chubu Electric Power

Co. for the long-term supply of LNG to

the Japanese utility amounting to more

than 120 cargoes. Under the agreement

Chubu will purchase up to 122 cargoes

over a period of 21 years, starting in 2014,

BG said. The LNG will be supplied from

BG’s global LNG portfolio, including the

Queensland Curtis LNG (QCLNG)

Project under development by BG's

Australian subsidiary, QGC. BG

Executive Director Martin Houston said

of the transaction: “We are very pleased

to have a long-term partnership with

Chubu Electric, one of the most

experienced and innovative LNG buyers

globally, and proud that we can assist in

meeting the long-term energy needs of

Japan.” Executive Vice President of BG’s

Australian operations and Managing

Director of QGC Catherine Tanna said

the agreement built on the already close

and productive relationship between

Chubu and BG. “We welcome Chubu

Electric as a foundation customer of

QCLNG,” Tanna said. In March 2011, BG

signed a sales agreement with Tokyo Gas

Co. for the supply of 1.2 million tonnes of

LNG for 20 years from QCLNG. That

agreement with Togas comes into force in

Newsindex

The ‘Maersk Ras Laffan’ in the Maersk shipping company’s distinct blue is part of the LNG fleet put up for sale

p8-16:LNG 3 17/06/2011 09:37 Page 20

LNG journal • June 2011 • 9

NEWS

2015. QCLNG is also underpinned by

sales agreements including 3.6 million

tonnes per annum being sold to China

National Offshore Oil Corp., some 1.7

MTPA destined for GNL Chile, and a 20-

year agreement to supply up to 3 MTPA

to customers in Singapore.

BG posted a 14 percent drop in first-

quarter profits from its LNG shipping

and marketing unit to $501 million

compared with $585M in

the same quarter a year

ago BG said the profits

drop was because the 2010

first quarter numbers

“benefited from strong

weather-related gas

demand.” LNG operating

profit for the whole of 2011

was expected towards the

upper end of a $1.9 billion

to $2.2Bln range,” the

company said. “It was a

challenging quarter for our

E&P operations, with civil

unrest in North Africa,

flooding in Australia, an

increase in UK tax and a

shutdown in the North

Sea,” said Chief Executive

Frank Chapman. “We now

expect modest production

growth in 2011. The plans

for a ramp-up in production

in 2012 and 2013, as well as

our 2020 goals, are

unaffected and are

supported by significant

progress with our growth

projects in Brazil, the USA and

Australia,” Chapman added. LNG capital

investment of $399M in the quarter

included $366M in Australia, BG said.

Among first-quarter highlights, BG cited

a sales agreement with Tokyo Gas for the

supply of 1.2 million tonnes of LNG a

year for 20 years from 2015. Togas will

be supplied with LNG from the

Queensland Curtis LNG facility in

Australia, and from the group’s global

LNG portfolio. BG also signed a sales

agreement with another Japanese utility

Chubu Electric Power Co. for the supply

of 122 LNG cargoes over 21 years,

starting in 2014. “Progress continued

with the QCLNG project during the

quarter. Mitigation of the effects of the

severe flooding, which has primarily

impacted the drilling programme, is in

hand with the 2014 first LNG date

unchanged,” BG said.

CHENIERE Energy said it received

an order from the US Department of

Energy with authorization to export up

to 16 million tonnes per annum of LNG

to any country from the Sabine Pass LNG

facility in Louisiana. The order expands

on the authorization the Sabine plant

received in September 2010 for the

export of LNG only to Free Trade

Agreement countries. It also concludes

one of the key regulatory requirements

necessary for the Sabine Pass

liquefaction project from which the

company intends to export liquefied

natural gas from excess US supplies,

Cheniere said. The authorization is

conditional on the completion of the

Federal Energy Regulatory Commission

review process and on Sabine Pass

starting export operations within seven

years. “This concluding authorization by

the DOE is a significant milestone for our

liquefaction expansion project at Sabine

Pass that will transform our terminal

into the first bi-directional LNG

processing facility capable of importing

and exporting LNG,” said Cheniere Chief

Executive Charif Souki. “Our terminal,

designed with substantial operating

flexibility and strategically located on the

Gulf of Mexico, will provide customers

the option to purchase or sell LNG from

and to U.S. markets,” he added. “This is

possible only because of the unique depth

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Managing Director of BG Australia Region Catherine Tanna (left) and Managing Executive Officer of Chubu ElectricPower Yuji Kakimi complete the 21-year sales and purchase agreement for supply of LNG, starting in 2014

p8-16:LNG 3 17/06/2011 09:37 Page 21

already begun for the investors to build a

fourth Train once the venture comes on

stream. Chevron signed a similar supply

agreement in January 2011 with

Japanese utility Kyushu Electric Power

for 300,000 tonnes per annum of Gorgon

cargoes.

CLASS NK, or Nippon Kaiji Kyokai,

the Japanese classification society, says it

has new rules for floating offshore

facilities for LNG production, storage and

offloading. Class NK said that although

the FLNG sector remains in its infancy,

it is expected to grow rapidly in the near

future and the new guidelines will

address growing demand. “Ongoing

environmental and logistical concerns

related to onshore gas production have

helped spur new interest in offshore LNG

and LPG projects,” said Class NK

Natural Resource and Energy

Development Project Team Leader

Hirofumi Takano. “With several of these

projects entering the design phase, there

has been a growing need for clear

technical guidelines for the construction

and survey of offshore gas facilities, and

these new guidelines are an important

step in that process,” Takano said. Due to

their highly sophisticated nature,

offshore gas facilities have primarily

been evaluated on a project-by-project

basis, and there has been a lack of clarity

about which class rules need to be

applied, a factor which these new

guidelines address, Class NK said. “For

example,” said Toshiyuki Shigemi,

General Manager of the Class NK

Development Department, “LNG FPSOs

fall under both the scope of the our rules

for FPSOs developed in 2009, as well as

our rules for vessels carrying gas in bulk.

With these new guidelines, however,

we’ve a created a single reference for all

the rules that apply to floating gas

facilities.” Class NK said its guidelines

are “more than just a compilation of

existing rules” as they also incorporate a

number of requirements exclusive to

offshore gas facilities. “As floating

structures, the design environmental

conditions and mooring system are of

great importance, so we’ve included

complete information on analysis of

environmental conditions and mooring

systems, as well hull structural

requirements, in our guidelines,” Class

NK said. The guidelines also cover the

wide range of other rules and

requirements that apply to such

structures, including rules for production

machinery, piping arrangements and

other equipment. The release of the

“Guidelines for Floating Offshore

Facilities for LNG/LPG Production,

Storage and Offloading” follows closely on

the official establishment of Class NK’s

Natural Resource and Energy

Development Project Team in February.

“With this new team, we have brought

together Class NK’s top experts from

both the LNG and the offshore sectors,

and these guidelines are the first result

of our increased commitment to this

growing sector,” Takano said.

EDF, the French utility and LNG player,

said it’s going ahead with plans to

develop an LNG import terminal near

the Channel port of Dunkirk at a cost of

around 1.5 billion euros ($2.2Bln). EDF

said its Dunkerque LNG subsidiary will

now invest the funds for the terminal to

be built at Le Clipon. Approval has

already been granted by the Dunkirk

port authorities. The French company

will be in partnership with several

European natural gas companies in the

project. “These will now be invited to

confirm their participation, following

EDF's commitment,” the company said.

The terminal is expected to come into

service in 2015 and give France a

northern coast entry point for LNG.

France’s current import network is

concentrated on the Atlantic coast at

Montoir-de-Bretagne and at Fos Tonkin

and Fos Cavaou near the southern

Mediterranean city of Marseilles, where

the main importers are GDF-Suez and

Total. The Dunkirk terminal will have an

annual regasification capacity of 13

billion cubic metres of natural gas. “The

new terminal will give EDF a balanced

and diverse portfolio of sources for the

supply of natural gas, allowing the group

better to meet the needs of its final

customers with dual energy offerings and

optimizing supplies to its gas-fired power

stations,” EDF said. “Within the Dunkirk

region the project will have a formative

impact on employment, recruiting up to

1,850 people during construction work on

the terminal between 2012 and 2015.

Once in operation, the facility will create

around 250 jobs in either direct operation

of the terminal or other port professions.”

Three project managers will be jointly

responsible for carrying out the project:

the Grand Port Maritime de Dunkerque

will build the port infrastructure, EDF

the industrial installations and GRTgaz

the connections to the gas transport

network.

EXMAR, the Belgian shipping group

with LNG interests, said it teamed up

with Pacific Rubiales to develop a small-

scale LNG export project in northern

Colombia. Pacific Rubiales, a Colombian-

Canadian exploration and production

player, and Exmar have begun front-end

engineering and design for the project.

Plans involve building a small

liquefaction barge and a pipeline from

the company’s La Creciente gas field to

the Caribbean coast and shipping to

targeted markets. The project developers

hope to export LNG to Caribbean and

Central American markets, Exmar said.

Technical details of the venture were not

released. Exmar currently has an

interest as an owner, part owner or

manager of nine LNG vessels, including

several in partnership with Excelerate

Energy of the US and used as floating

LNG import facilities. The Antwerp-

based company is also branching out

from the LNG shipping sector to expand

its activities along the LNG value chain.

Pacific Rubiales, based in Canada,

produces natural gas and heavy crude

oil, It also owns a company called Meta

Petroleum Corp., a Colombian oil

operator with interests in the Rubiales

and Piriri oil fields in the Llanos Basin

in association with Ecopetrol, the

Colombian national oil company. Pacific

Rubiales, whose shares are traded

on the Toronto Stock Exchange, also

owns all of the La Creciente natural

gas field in the Sucre region of northern

Colombia.

10 • LNG journal • The World’s Leading LNG publication

NEWS

of the markets in the Gulf Coast, both on

the production and consumption side;

with approximately 30 Bcf/d of fully

integrated physical supply, pipeline

infrastructure, storage, and market

delivery capability,” he said. “With the

unprecedented growth in unconventional

reserves, supply of natural gas continues

to outpace demand dramatically. There

are currently an estimated 3,500 wells

that have been drilled but not completed

with the potential to continue to boost

production. The US has an opportunity to

become a significant supplier in the

global energy markets,” Souki added.

Cheniere said construction of the Sabine

Pass liquefaction facility is expected to

commence in 2012 and be completed by

2015. Cheniere’s Sabine Liquefaction

subsidiary has already entered into non-

binding agreements for an aggregate of

up to 9.8 million tonnes per annum of

processing capacity, well exceeding the

targeted capacity of 7.0 MTPA to

complete the first two Trains. Sabine

has begun the process of converting

its memoranda of understanding into

definitive agreements whereby

customers will secure their processing

capacity under long-term take-or-pay

contracts.

CHEVRON Corp. said it signed a Sales

and Purchase Agreement with JX Nippon

Oil for a portion of Chevron's offtake of

LNG from the $40-billion Gorgon LNG

project under development on an island

offshore Western Australia. Under the

binding agreement, JX Nippon will

receive 0.3 million tonnes per annum of

LNG from Gorgon for 15 years, Chevron

said. John Gass, President of Chevron

Gas and Midstream, welcomed the JX

Nippon Oil transaction: “We are pleased

to have JX Nippon Oil as a customer of

the Gorgon project. Chevron has a long-

standing relationship with JX Nippon

Oil, and we look forward to continuing

to grow our relationship.” Roy

Krzywosinski, Managing Director of

Chevron Australia, said: “The agreement

is another step towards commercializing

our equity natural gas in Australia,

further demonstrating Chevron's leading

ability to meet long-term demand growth

in Asia-Pacific. Construction of the

Gorgon project is progressing well with

first gas expected in 2014.” Chevron is

the operator of the Gorgon project and

holds a stake of 47 percent. The initial

Gorgon project development will include

a three-rain, 15 MTPA LNG facility and a

domestic gas plant. However, moves have

Roy Krzywosinski, ManagingDirector of Chevron Australia. See story

p8-16:LNG 3 17/06/2011 09:37 Page 22

LNG journal • June 2011 • 11

NEWS

EVERETT LNG import terminal in

Boston, Massachusetts, owned by GDF-

Suez subsidiary Distrigas, has for the first

time sold LNG as vehicle fuel because the

price of LNG reaching the

US is lower than the price of

diesel fuel and gasoline. The

GDF-Suez facility is selling

the LNG to a refuelling

station for a fleet of waste-

collection trucks owned by a

company called Enviro

Express in Bridgeport,

Connecticut. “Interest in

LNG to power fleet vehicles

is increasing significantly as

diesel fuel and gasoline

prices continue to climb,”

said Joe Murphy, vice

president, Sales and

Transportation for Distrigas

in the US. “The difference in

fuel and maintenance costs

and the environmental

benefits make LNG an

attractive vehicle fuel

alternative,” Murphy said.

The Everett LNG receiving

terminal, which began

operations in 1971,

currently supplies

regasified LNG cargoes to

most of the natural gas

utilities in New England.

The transaction to use

imported LNG for truck fuel

is partially funded by the

American Recovery and

Reinvestment Act of 2009,

and the $6.2 million project

is also part of the larger

Connecticut Clean Cities

Future Fuels project.

The growing shale-gas

developments in the US has

led to a re-think on how to

adapt to the lower natural

gas price environment in

the US compared with

Europe and the Asia-Pacific

region. In addition to

projects for using LNG as

truck fuel some US LNG

import terminals plan to

build liquefaction facilities

to export surplus and lower-

priced US natural gas.

Distrigas says that by

switching to LNG, the truck

fleet users will be able to

replace their purchase of

about 500,000 gallons of

diesel fuel annually and

remove hundreds of tonnes of harmful

emissions from the air. Adding to the

environmental benefit, the Bridgeport

fueling station is a closed system which

recaptures boil-off from the LNG that

would otherwise vent into the atmosphere

and compresses it to be stored as

compressed natural gas. “LNG is lighter

than diesel, so we can go farther, cleaner,

and improve load efficiency by hauling

more with the same vehicle,” said Bill

Malone of Enviro Express.

p8-16:LNG 3 17/06/2011 09:37 Page 23

12 • LNG journal • The World’s Leading LNG publication

NEWS

natural gas in Asia is driven by the

region’s need for cleaner, secure, safe and

reliable energy - and that’s what GLNG

will provide,” Knox stated. GLNG alone

will supply 11 percent of Korea’s

domestic gas needs and 9 percent of

Malaysia’s gas consumption.

INPEX Corp. of Japan said it would

extend the reach of its LNG imports by

building a new pipeline linking the cities

of Itoigawa and Toyama to its planned

Joetsu LNG import terminal. The 102-

kilometres Toyama Line along a coastal

route will supply LNG-sourced natural

gas to Nihonkai Gas Co, and other

customers, starting in late 2014, Inpex

said. It is one of the first additional

energy infrastructure projects announced

since the March earthquake and tsunami

caused widespread damage to existing

structures, including the Fukushima

nuclear power generating facilities

owned by Tokyo Electric Power Co. The

new pipeline will be part of the natural

gas transmission network linking the

Tokyo metropolitan areas on Honshu

Island and seven other cities, it added.

The new Inpex LNG import terminal is

in the port of Naoetsu in Joetsu city and

is part of a build-up of Japan’s LNG

terminal network and gas-fired power

generation facilities. Japanese LNG

imports are set to rise even more than

previously forecast to meet power

generating shortfalls caused by the

earthquake.

JGC Corp., the Japanese LNG

engineering company, overhauled its

executive team and appointed a new

President to “strengthen and rejuvenate”

its management structure. The Japanese

company has been at the fore-front of the

development of the LNG industry and

over the past 20 years has worked on the

building of the world’s main liquefaction

plants in countries such as Nigeria and

Qatar. Koichi Kawana was appointed as

the new President to succeed Masahiko

Yaegashi. In addition, four executives

have been promoted to more senior

positions, with Masayuki Sato named as

the new Managing Director and Chief

Financial Officer. The appointments are

effective from June 29, 2011, after the

annual meeting of shareholders, JGC

said. Other appointments include

Tadashi Ishizuka as Executive Vice

President and director, and Yutaka

Yamazaki and Eiki Furuta as Senior

Managing Directors. Six other senior

executives retired, the company said.

GDF-SUEZ said it agreed to sell 2.5

million tonnes LNG to Malaysian state

energy company Petronas over a 42-

month period starting in August 2012

following similar supply deals with Korea

Gas Corp. and China National Offshore

Oil Corp. Petronas is constructing an

LNG import terminal in Malacca on the

western coast of Malaysia, with capacity

to regasify of 3.8 million tonnes per

annum of LNG. The Malaysian company

is the second producer in the Asia-Pacific

to decide on LN imports after Indonesia.

The two Asian countries supply their

LNG under long-term contracts to

countries such as Japan but are seeking

their own LNG volumes for domestic use

as natural gas demand increases. The

GDF-Suez LNG cargoes will be sourced

from its portfolio, which includes offtake

from Algeria, Egypt, Nigeria, Norway,

Trinidad & Tobago and Yemen. The

French company currently has 16.5

million tonnes per annum of LNG

supplies and is also set to establish a

project presence in the Asia-Pacific region

through its development plans in

Australia. GDF-Suez is developing the

Bonaparte LNG project offshore

Australia. The company hopes to produce

2 MTPA of LNG from a floating

production, storage and offloading unit in

what will be one of the world’s first

FLNG production projects. Gérard

Mestrallet, Chairman and Chief

Executive of GDF-Suez, said of the

medium-term contract with Petronas:

“This agreement concluded with Petronas

LNG confirms GDF-Suez’s ambition as

illustrated by other medium-term

agreements recently concluded with

Kogas for the delivery of 2.5 MTPA LNG

between 2010 and 2013, or with CNOOC

for the delivery of 2.6 MTPA of LNG from

2013 to 2016.” Petronas itself has a

growing portfolio of interests along the

LNG chain. In addition to its LNG

production plants in Bintulu, Malaysia,

the company has a stake in the Egyptian

LNG plant at Idku, the Gladstone LNG

project in Queensland, Australia, and the

Dragon LNG import terminal in the UK.

GLNG, the coal-seam-gas to-LNG

project on being developed on Curtis

Island by four companies led by

Australia’s Santos, formally launched the

US $16-billion venture at a ceremony in

Queensland attended by politicians and

executives. The GLNG project sees

Santos team up with Petronas of

Malaysia, France’s Total and Korea Gas

Corp., for what is one of four CSG-to-LNG

ventures in the area around the eastern

Australian port of Gladstone. The Santos-

led project will bring CSG by way of a

420-kilometre from the Bowen and Surat

Basins in south-east Queensland to a

liquefaction plant where two Trains will

produce a combined 7.8 million tonnes

per annum of LNG. First LNG is

expected in 2015 and two of the

shareholders, Petronas and Kogas, have

already signed up as purchasers of 7

MTPA of the offtake. The original GLNG

developers, Santos and Petronas, brought

in Total and Kogas to spread the costs of

the multi-billion project. Santos is still

the largest shareholder with a 30 percent

stake in GLNG while Petronas and Total

each hold 27.5 percent. The Kogas stake

is 15 percent of the project. Australian

Prime Minister Julia Gillard officially

launched work on the GLNG project at

Gladstone where three other projects are

also under development involving

companies such as BG Group of the UK,

ConocoPhillips and Royal Dutch Shell.

“Construction on Curtis Island heralds

an economic boost for Gladstone,

Queensland and Australia - and

represents another significant

commercial and strategic link between

Australia and Asia,” said Santos Chief

Executive David Knox. “Over the life of

the project, GLNG will pay around A$40

billion in Federal Income Tax,” he added.

Queensland Premier Anna Bligh said the

GLNG project had already added over

A$2Bln to Queensland’s economy and

would make a “substantially greater”

contribution, including the creation of

6,000 jobs. Knox added that the start of

work on the GLNG plant was the

culmination of more than three years of

planning and preparation. “Curtis Island

is the engine room for the whole project,”

Knox said. “This is where coal-seam gas

from Queensland’s world-class fields will

be converted to LNG and exported to

Asia,” he said. “The growing demand for

June6th FLNG Asia-Pacific SummitParkroyal Beach Road HotelSingaporeJune 28-29www.flngsummit.com

IBC Energy’s FLNG MasterclassLe Meridian, Piccadilly, LondonJune 23-24 www.informaglobalevents.com

LNG ChinaBeijing, ChinaJune 28-July 1www.lngchina.org

SeptemberGlobal Gas Trading & TechnologyConferencePerth Convention ExhibitionCentre, W. AustraliaSeptember 19-20www.globalgas.info

LNG Fuel for ShippingStockholm, SwedenSeptember 20-21,www.informaglobalevents.com

LNG Global CongressHilton Tower Bridge, London, UKSeptember 25-29 www.informaglobalevents.com

IBC Energy FLNG Masterclass Rio,GW Marriot, Copacabana, RioSeptember 26-27www.informaglobalevents.com

OctoberSEAAOC 2011 (South East Asia,Australia Offshore Conference)Darwin Convention CentreAustraliaOctober 5-7 www.seaaoc.com

November10th Annual Cryogen-Expo – 2011Expocentre FairgroundsMoscow, RussiaNovember 8-10www.cryogen-expo.com

CWC 12th World LNG SummitCavalieri Hotel, Rome, ItalyNovember 14-17 www.world.cwclng.com

European Autumn Gas ConferenceParis Montparnasse, FranceNovember 15-16www.theeagc.com

LNG Outlook Australasia 2011Pan Pacific, Perth, AustraliaNovember 28 - 30 www.terrapinn.com

Diary of events

p8-16:LNG 3 17/06/2011 09:37 Page 24

NEWS

LNG journal • June 2011 • 13

Kawana, the new President, is aged 54.

He joined the company in 1982 and after

working in London and the Middle East

has held a string of senior positions in the

JGC Global Marketing Division. JGC is

currently working on the new Hachinohe

LNG import terminal in Japan for JX

Nippon Oil. The terminal will be Japan’s

28th import facility. JGC has built more

than one third of Japan’s LNG terminal

network.

LAKE CHARLES LNG import

terminal in Louisiana is seeking to

become an LNG exporter. BG Group of

the UK and Texas-based Southern Union

Co. applied for US permits to export 15

million tonnes per annum from the

facility. A joint venture company called

Lake Charles Exports has applied to the

US Department of Energy for an export

permit lasting 25 years. “The companies

are jointly developing plans to install

liquefaction facilities that would permit

gas to be received by pipeline at the

terminal and liquefied for subsequent

export,” the application said. BG up until

now has been the leading importer of

LNG into the US with its capacity rights

at the Lake Charles LNG terminal and at

a second import terminal at Elba Island

in Georgia. The move by BG and

Southern follows similar applications by

the owners of the LNG facilities at

Sabine Pass in Louisiana,

Freeport in Texas and Cove

Point in Maryland to export

US natural gas surpluses

created by the development

of the shale-gas industry.

All the LNG facilities

involved were established

as importers until the

slump in US gas prices

made LNG imports into the

US uneconomic as cargoes

were diverted to higher-

priced markets in Europe

and the Asia-Pacific region.

BG has been building up its

stakes in US shale-gas

resources. Over the past

two years, BG has

purchased major interests

in the Haynesville and

Marcellus shale plays, as

well as other production in

Texas, Louisiana, West

Virginia and Pennsylvania.

The Lake Charles LNG

terminal is one of the oldest

in the US, having been

certified by the US Federal

Energy Regulatory Commission since

1977. BG has been an importer there

since 1982. BG has brought LNG into

Lake Charles from the Atlantic LNG

plant in Trinidad and from other LNG

liquefaction holdings, such as Equatorial

Guinea LNG in West Africa owned by

Marathon Oil, and elsewhere. The Lake

Charles terminal currently has four large

LNG storage tanks with capacity of

425,000 cubic metres. The terminal’s

natural gas liquids processing facilities

allow the extraction of ethane and other

heavier hydrocarbons from the LNG

stream. “Following completion of the

project, the Lake Charles terminal will be

bi-directional, and its peak and sustained

send-out capabilities will not be affected,”

the companies said.

LITHUANIA, the Baltic state formerly

a part of the Soviet Union, could become

an importer of LNG from the US after an

agreement signed with Cheniere Energy

of Houston, Texas. Cheniere plans to

produce LNG at its Sabine Pass LNG

facility in Louisiana and said it signed a

memorandum of understanding on

supplying LNG to Lithuanian oil

terminal owner and LNG terminal

developer, Klaipedos Nafta, at

Lithuania’s embassy in Washington D.C.

Lithuania has just announced plans to

build an LNG import terminal to receive

up to 2.2 million tonnes per annum at a

facility to be built at the port of Klaipeda,

where Klaipedos Nafta already operates

a crude oil and oil products terminal.

“Due to intensive shale-gas

developments, the US has the potential

to become a meaningful exporter of

natural gas, which would not only benefit

our project but our country as well, by

providing a more diversified source of

supply in Lithuania and boosting energy

security,” said Rokas Masiulis, General

Manager of Klaipedos Nafta. Charif

Souki, Chief Executive of Cheniere, said:

“Exporting LNG to Lithuania will allow

one of our allies to diversify its natural

gas supply, increase its energy security

and strengthen its economy. We look

forward to working with Klaipedos Nafta

on developing solutions for their natural

gas needs in Lithuania.” Klaipedos Nafta

is in the process of building the first LNG

import terminal on the Eastern Baltic

coast for Lithuania’s needs and

potentially for export to its Baltic region

neighbours, Latvia and Estonia, as a

supplement to Russian natural gas

supplies. “The development of the

Klaipeda LNG terminal is a critical

component in the plan to open the energy

markets in the Baltic region,” the

statement said. Under the agreement

just signed, Cheniere and Klaipedos

Nafta will proceed with negotiations on a

firm LNG supply deal. Cheniere is one of

four US LNG import terminal owners

planning to export LNG because US

shale-gas developments are expected to

produce a surplus of natural gas at

prices that would make exports from the

US economic.

MEO, the Australian developer of the

niche Tassie Shoal LNG and methanol

project in the Timor Sea, has signed a

deal with Italy’s ENI to secure funding

for exploration and appraisal drilling of

nearby natural gas discoveries. The

binding agreements give ENI a 50

percent in the Heron gas discovery in

exchange for funding two wells and

similar options on its Blackwood

discovery in the same area. Tassie Shoal

is centrally located to seven undeveloped

gas fields within a 150 kilometres radius.

MEO holds 100 percent equity in two of

these fields, Heron and Blackwood. The

latter is a modest-sized gas resource with

high CO2 content. In contrast, the Heron

field has the potential to host an LNG-

scale gas resource with potential to have

higher quality (i.e. lower CO2) gas. MEO

has secured its development location and

environmental approvals to construct

and operate a single 3 MTPA LNG plant

and two 1.75 MTPA methanol plants on

Tassie Shoal, an area of shallow water in

the Timor Sea, some 275km north-west of

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p8-16:LNG 3 17/06/2011 09:37 Page 25

14 • LNG journal • The World’s Leading LNG publication

NEWS

Darwin. Previous Heron field drilling was

the subject of cyclone interruptions and a

collapsed borehole, meaning the well had

to be abandoned prior to being fully

evaluated. MEO then began a process of

seeking a farm-in partner to assist with

appraising and potentially developing the

discovery and has now announced the

partnership with the Italian energy

company. For the Heron agreement ENI

will earn 50 percent of the Heron gas

discovery by funding MEO’s costs for the

drilling of two wells and ENI will be the

operator of the permit. ENI has 60 days

after the first well has been drilled to

elect to either drill a second Heron well

or withdraw from the agreement, a

statement explained. ENI also has an

option, exercisable within 60 days after

the first Heron well has been drilled, to

elect to earn 50 percent in the Blackwood

gas discovery by carrying MEO’s costs of

acquiring a minimum of 500 square

kilometres of 3D seismic and drilling one

well in the Blackwood area. The Italian

company has a further option to acquire

an additional 25 percent interest in both

discoveries by funding MEO’s share of

the work programme required to reach a

Final Investment Decision (FID) in either

Heron and/or Blackwood, upon

achievement of which ENI will make a

one off bonus payment of US$75 million

to MEO. “This agreement is in line with

MEO’s strategy to partner with leading

companies to unlock value in its

portfolio,” MEO said. “Following

successful appraisal of the Heron and/or

Blackwood gas discoveries the joint

venture will evaluate all potential

commercialisation paths for the

resources,” it added.

PETRONAS of Malaysia and Progress

Energy Resources of Canada signed a

US$1.7-billion deal for the Malaysian

company to invest in shale-gas assets and

develop an LNG export terminal project

on the west coast of Canada. Canadian

mid-sized energy player Progress said

Petronas would pay US$273 million in

cash by the third quarter of 2011 and a

further $US824M towards capital

spending by Progress to develop its

British Columbia shale-gas holdings in

the Montney region over the next five

years. Petronas will additionally provide

a standby equity financing commitment

of up to US$615M for Progress's capital

needs for development of the LNG export

venture. Petronas will own 80 percent of

the LNG project and Progress the

remainder. The Malaysian company joins

Apache Corp., EOG Resources, Shell and

various other players who are planning

LNG exports to the Asia-Pacific region

from shale-gas resources in Western

Canada. Petronas is currently the world’s

third-largest producer of LNG from its

Bintulu complex in Malaysia comprising

three LNG plants. In addition, the

Malaysian company also has a

substantial stake in one of the main coal-

seam-gas-to LNG projects being

developed in Australia by domestic

producer Santos. Under the Petronas-

Progress deal in Canada, Progress will

sell 50 percent of its working interest in

its Altares, Lily and Kahta properties in

Montney to Petronas, the statement

added. “We are very pleased to form this

long-term partnership with Petronas,”

said Michael Culbert, President and

Chief Executive of Progress. “They share

our belief that our North Montney shale

assets are a world-class resource that

deserves significant investment. We look

forward to benefitting from Petronas’s

significant global expertise including

their leadership in developing

infrastructure and accessing LNG

markets,” Culbert added. “This

partnership will also generate

substantial economic benefits for local

communities and the province of British

Columbia, while leveraging the

environmental benefits of Canada’s

abundant and clean-burning natural gas

resources globally,” he said. The LNG

export joint venture will launch a

feasibility study to evaluate building and

operating the new LNG export facility on

the west coast of British Columbia.

Petronas would be the operator of the

LNG facility, and both companies would

jointly market the LNG. “Canada is

poised to take a larger role on the world’s

energy stage,” said Culbert. “Developing

new export options for Canadian natural

gas producers is a logical step in

connecting our vast resources with

growing Asian demand,” he added. “We

look forward to working with West Coast

British Columbia communities as we

pursue this opportunity to build a new

facility that will add value to British

Columbia’s natural resources while

creating considerable long-term local

economic benefits,” he said. For the shale-

gas assets part of the transaction,

Petronas will own 50 percent of the North

Montney joint venture comprising

149,910 working interest acres and

Progress will be the operator. The North

Montney lands represent about 20

percent of Progress’s rights in its

northeast British Columbia Foothills

land holdings, which total around

700,000 net acres. Progress holds about

900,000 net acres of Montney rights over

its entire British Columbia and Alberta

land base, making it one of the largest

Montney land rights holders. The

Canadian company said the joint venture

shale-gas properties “included five wells

with minimal production at this time.”

The closing of the transaction is subject

to the execution of definitive agreements

and receipt of regulatory approval, the

statement concluded.

QATARGAS, the world’s largest

corporate producer of LNG, said it added

Greece to its roster of customers when a

first cargo was delivered to the

Revithoussa Island LNG import

terminal, located west of the Greek port

of Piraeus. The cargo was sold to the

Netherlands-based hydrocarbons trading

company Vitol, which was acting on

behalf of Greece’s state-owned natural

gas supply company DEPA. The 141,000

cubic metres capacity LNG carrier “Golar

Maria” delivered the cargo to Greece

rather than one of the large Qatari

carriers as the Greek terminal can only

handle conventional-sized ships, and

because of the nature of the cargo

transaction. “Due to Revithoussa’s small

regas terminal capacity, the ‘Golar Maria’

was found well suited to the expected

discharge quantities to keep boil-off gas

to a minimum between parcels,”

Qatargas said. Commenting on the first

LNG shipment by Qatargas to Greece,

An LNG cargo from Qatargas being delivered recently to the Revithoussa LNG import terminal in Greece

p8-16:LNG 3 17/06/2011 09:37 Page 26

LNG journal • June 2011 • 15

NEWS

Khalid Bin Khalifa Al-Thani, Chief

Executive of Qatargas, said: “We are

pleased to supply LNG where it is needed

most. Greece is the latest addition to our

growing customer portfolio in Europe and

we are happy that our LNG will keep the

lights on in Athens.” Europe is currently

one of Qatargas's largest markets

accounting for around 45 per cent of

delivered cargoes. Qatargas produces 42

million tonnes per annum from its seven

LNG trains, four of which are the world’s

largest with output of 7.8 MTPA each.

SHELL said it signed a heads of

agreement for the long-term supply of

two million tonnes per annum of LNG to

CPC Corp. of Taiwan. Shell said its Shell

Eastern LNG subsidiary agreed the

transaction with the Taiwanese energy

company for a period of 20 years starting

in 2016. This is the first long-term LNG

deal between Shell and CPC and the

agreement will see Shell become one the

main suppliers of LNG to Taiwan, a

statement said. The terms of the HOA

provides for CPC and Shell to work

together and conclude detailed sale and

purchase agreements in the coming

months. Taiwan’s CPC opened a second

LNG import terminal two years ago as its

cargo requirements have grown.

However, the emergence of China as an

LNG buyer has meant more competition

in the Asia-Pacific region for long-term

supplies at economical prices. Taiwan is

currently the fourth-largest LNG market

in the Asia-Pacific region in terms of

long-term supply contracts behind Japan,

South Korea and now China. Taiwan’s

newest terminal, the Tai-Chung facility,

has three LNG storage tanks, each with a

capacity of 160,000 cubic metres. Its

Yung-An LNG terminal in southern

Taiwan has six storage tanks with

combined capacity of 690,000 cubic

metres. Among Taiwan’s other supply

contracts are one with Qatar’s RasGas for

2.7 MTPA over 25 years, and three

contracts with suppliers in Indonesia and

Malaysia for more than 5 MTPA.

STENA, the Swedish shipping

company, said it bought three LNG

carriers for $700M from the Taiwanese

company TMT and expected charter rates

of over $100,000 per day from each

vessel. One of the vessels was built in

2006 with 145,000 cubic metres capacity

and was renamed the “Stena Blue Sky”.

The other two carriers are new-builds of

174,000 cubic metres capacity. They were

completed in 2010 and have been re-

named the “Stena Clear Sky” and the

“Stena Crystal Sky”. “The three tankers

are all ultra-modern and ice-classed. The

‘Stena Blue Sky’ is currently chartered by

Russian Gazprom with 22 months

remaining on its contract,” Stena said.

The carriers will be under the operational

control of Stena Bulk, whose President

Ulf G. Ryder, said: “We believe this to be

a very good investment. LNG accounts

for a significant part of the growth in the

global energy supply and there is

currently a shortage of LNG tankers.

Consequently, we expect the two newly

built vessels to directly command freight

rates in excess of $100,000 per day.”

Capacity utilisation of the 359 LNG

carriers worldwide has soared in the past

eight months with global LNG demand.

The Japanese earthquake and tsunami

in March further tightened the market as

spot cargo deliveries were arranged by

utilities in Japan which is the world’s

largest LNG buyer. According to Stena,

the demand for transportation of LNG is

expected to rise about 8 percent per

annum over the next 10 years. “Having in

this situation the liquidity and

operational know-how to be able to

purchase these three vessels so quickly,

two of which are so new that they have

not even been delivered from the

shipyard yet, gives our LNG investment

an excellent starting point,” Ryder stated.

TECHNIP, Europe’s leading LNG and

energy engineering company, has two

new woman directors, bringing to three

the number now sitting on the French

firm’s board as part of a diversity policy.

The French company's annual meeting

ratified the co-option of Marie-Ange

Debon announced earlier and approved

the nomination of two new female

directors, C. Maury Devine and Leticia

Costa. Technip said the new

appointments brought the percentage of

women on the company’s Board to 27

percent (three out of 11), satisfying the

p8-16:LNG 3 17/06/2011 09:37 Page 27

legal objective for French companies of 20

percent by 2014. “They are also part of a

wider aim to renew and diversify the

composition of the Board, which now

includes American and Brazilian

members who have an in-depth

understanding of the group’s major

clients and markets such as North

America, the North Sea and Brazil,”

Technip said. Marie-Ange Debon is

General Secretary of the Suez

Environnement Group and is a member

of the College de l'Autorité des Marchés

Financiers (the French Financial Market

Authority). Prior to joining Suez

Environnement in 2008, Debon has

served in various positions in both the

public and private sectors. Marie-Ange

Debon is a graduate of the Paris business

school, the École des Hautes Études

Commerciales, and the Ecole Nationale d'

Administration and has a Master's

Degree in Law. C. Maury Devine is a

member of the Board of FMC

Technologies and John Bean

Technologies. She serves on the Audit

Committee and Nominating and

Governance Committee of both

companies. She is also a member of the

Council on Foreign Relations and is a

member of the independent Nominating

and Governance Committee of Petroleum

Geo Services. She served as Vice-

Chairman of the Board of Norway’s Det

Norske Veritas from 2000 to 2010, and

was a fellow at Harvard University’s

Belfer Center for Science and

International Affairs between 2000 and

2003. Additionally she held various

positions in ExxonMobil Corp. between

1987 and 2000, notably President and

Managing Director of ExxonMobil’s

Norwegian affiliate from 1996 to 2000.

From 1972 to 1987, she held various

assignments in the US government

notably in the US Department of Justice,

the White House and the Drug

Enforcement Administration. She is a

graduate of Middlebury College, the

University of Maryland and Harvard

University (Masters of Public

Administration). The third woman Board

member, Leticia Costa, has been a

partner in Prada Assessoria and

Coordinator for the Center of Strategy

Research at Insper. In January 2011, she

became a Director of the Automotive

Engineers Association in Brazil. She

currently serves as board member of

FAMA, a private equity fund in Brazil, of

Localiza, the largest car rental company

also in Brazil and of Sadia, a food

manufacturer. In 1986, she joined Booz &

Co. (formerly Booz Allen Hamilton) and

in 1994, became a Vice President and in

2001 was appointed President of the

operations in Brazil. She also served the

firm’s Board of Directors. At Booz & Co.,

Costa completed a wide range of

assignments in Europe and Latin

America, and also conducted studies in

North America and Asia. Prior to joining

Booz & Co., she worked from 1982 to

1984 as a systems analyst for Indústrias

Villares S.A. Costa is a graduate of

Cornell University and of Escola

Politécnica of the University of São Paulo.

TIDELAND Signal of the UK was

chosen to supply all the warning lights

and buoys for the new Dubai Supply

Authority floating LNG import facility at

Jebel Ali port in the United Arab

Emirates. This is the latest in the list of

Tideland's LNG installations around the

world. The company has previously

supplied equipment for the port at Soyo

in Northern Angola, India's Dabhol Port,

Milford Haven in the UK, the Burrup

Peninsula terminal near Karratha in

Western Australia and Yemen's LNG

terminal at Balhaf, on the Gulf of Aden.

The Dubai LNG facility will be protected

by five special marker buoys, three fixed

navigation beacons installed on the

breakwaters and six beacons equipped

with Tideland's newest MLED-150EX

lanterns installed on the LNG wharf, the

company said. The buoys are Tideland's

SB-138 polyethylene units complete with

mooring equipment and SolaMAX-140/6

self-contained marine lanterns fitted

with the MaxiHALO-60 LED flasher. The

breakwater beacons, also solar-powered,

are Tideland's MaxLED-200 MaxLumina

lanterns, supplied complete with solar

arrays, maintenance-free batteries/

battery boxes and mounted on two-metre

galvanized steel stanchions. One of the

company's earliest port equipment

installations was for the Atlantic LNG

plant in Trinidad. The UK company is

part of the Tideland group whose

headquarters are in Houston,. Texas.

WOODSIDE Petroleum, the

Australian LNG producer and developer,

appointed Peter Coleman from

ExxonMobil to replace Don Voelte as

Chief Executive with salary and benefits

of over $2 million a year and a signing-on

package of around $3.6M in cash and

shares. Voelte, a US citizen from

Nebraska, announced in October 2010 he

was retiring from Woodside after seven

years when he built the Australian

company up to be a leading LNG player.

Woodside is currently bringing the Pluto

LNG project on stream and developing

two other projects, Browse LNG and

Sunrise Floating LNG. It is also a one-

sixth shareholder in Australia’s first

LNG plant, the North West Shelf facility

at Karratha. Coleman, an Australian

citizen from the state of Victoria, goes to

Woodside after 27 years with

ExxonMobil, where he filled a variety of

roles in Australia, Africa, Asia and the

United States. Coleman’s most recent

position was Vice President of the

ExxonMobil Development, with

responsibility for oil and gas

developments around the world. This

included ExxonMobil’s Papua New

Guinea LNG project and oil and gas

developments in Malaysia, Indonesia and

Australia. Previous key roles with

ExxonMobil included Vice President,

Americas, responsible for all activities

related to production in the US, Canada

and South America. Coleman joined

ExxonMobil from its Australian

subsidiary Esso. Woodside Chairman

Michael Chaney said Coleman’s

appointment followed an extensive

recruitment process which “considered a

strong field of internal and external”

candidates. “The board is delighted that

Mr Coleman has agreed to lead Woodside

through the company’s next phase of

growth,” Chaney said. Chaney paid

tribute to the achievements of Voelte, who

will step down as CEO and Managing

Director at the end of the month. “Mr

Voelte oversaw a significant expansion of

Woodside’s LNG portfolio and created a

strong ‘can do’ culture within the

company,” Chaney said. “He has made an

enormous contribution during his tenure,

leaving Woodside in a great position from

which it can continue to build,” he added.

Coleman said he was excited to be joining

Woodside, a company he had long

admired. “I have followed Woodside

closely since beginning my career in the

oil and gas industry nearly three decades

ago and I relish the opportunity to lead

this great Australian company,” he said.

“Woodside has an impressive portfolio of

Australian oil and gas assets right across

the development timeframe and I look

forward to growing the company as

successfully as my predecessors, and in a

manner which continues to provide

superior returns to shareholders,”

Coleman added. Voelte welcomed

Coleman’s appointment, saying his wide

industry experience and unique oil and

gas skills would stand him in good stead

in his new role. “I am confident that Mr

Coleman has the right qualities to take

Woodside through its next phase of

growth,” he said.

WOODSIDE entered into an

agreement to sell US$700 million of

corporate bonds into the US bond

market for institutional investors. The

bonds were to be issued by Woodside

Finance Ltd, a wholly owned subsidiary

of Woodside Petroleum Ltd, and will

consist of 10-year bonds with a coupon

of 4.6 percent. The bonds are guaranteed

by Woodside Petroleum and its wholly

owned subsidiary, Woodside Energy.

Woodside was Australia’s first LNG

producer as operator of the North West

Shelf venture in Western Australia with

majors oil companies. The first phase of

its Pluto LNG project in Western

Australia is scheduled to come on

stream in 2011 and the company is also

developing two other projects, Browse

LNG and Sunrise FLNG. “The funds will

be used for general corporate purposes

including, but not limited to, repayment

of some of Woodside’s existing debt,

which matures in 2011, as well as the

funding of our ongoing capital,” the

company said. Accordingly, the bonds

have been offered only to “qualified

institutional buyers” in the US pursuant

to Rule 144A under the US Securities

Act. The US 144a rule allows the debt to

trade to and from qualified institutional

investors and dramatically increases the

liquidity for private placements of

corporate debt. �

NEWS

16 • LNG journal • The World’s Leading LNG publication

Peter Coleman joined WoodsidePetroleum from ExxonMobil as newCEO of the Australian company

p8-16:LNG 3 17/06/2011 09:37 Page 28

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p17-25:LNG 3 17/06/2011 09:42 Page 1

18 • LNG journal • The World’s Leading LNG publication

FLNG DEVELOPMENT

Floating LNG’s time has come as Prelude project offshore Australia gets investmentLNG Journal, Asia-Pacific Editorn

After a decade of engineering research

and financial planning Royal Dutch Shell

is finally going ahead with its huge

investment programme directed at

Floating LNG.

The final investment decision was

taken for the Prelude FLNG venture

offshore northwest Australia to produce

3.5 million tonnes per annum of LNG -

and opening the way for similar

developments at other gas fields.

The FLNG facility being designed and

built by South Korea’s Samsung Heavy

Industries and France’s Technip will

make its debut by tapping into about 3

trillion cubic feet equivalent of resources

in the Prelude gas field and produce LNG

by 2017.

PartnershipShell said its FID meant its technology

partners Samsung and Technip could

proceed with the construction of the first

in a series of FLNG production hulls.

The Prelude FLNG project will be the

first Australian upstream project in

which Shell is the operator. It will be

located in the Browse Basin in the WA-

371-P permit area.

The Prelude gas was found in 2007

as an extension of the giant Ichthys

gas field in the neighbouring WA-285-P

permit block owned by Japan’s Inpex,

but was a separated gas accumulation

from Ichthys.

After making the discovery, Shell

began investigating the use of a floating-

production, storage, and offloading vessel

to develop the gas reserves.

Traditionally, LNG projects need more

than 5 Tcf of gas to construct offshore

platforms, pipelines to shore and land-

based processing plants.

EconomicBut the FLNG approach makes the

current reserves economic to recover and

with the possibility of additional

marginal gas fields in the area being

monetized. One such discovery close to

Prelude is called Concerto and is 10 miles

from Prelude.

Shell believes it has already advanced

the Prelude FLNG project at a rapid

pace, with first production of LNG

expected some 10 years after the gas was

discovered.

Shell has been steadily engaging with

stakeholders ever since, concerning the

Prelude FLNG project and the new

application of existing technology.

The environmental impact statement

was presented early on and Shell has

engaged on a regular basis with

Australian federal and state government

ministers and departments

MeetingsThese face-to-face meetings have

included presentations on the project,

explanations of FLNG facility technology

and safety parameters.

The concept of FLNG was then

introduced to a broader range of

stakeholders, including non-government

organisations, industry and Kimberley

community representatives.

These engagements provided an

opportunity for Shell to receive feedback

on the concept and its general application

to developing gas resources. Stakeholders

were also briefed on the Environmental

Referral which was submitted way back

in April 2008.

Following the Prelude FLNG FID,

Shell’s upstream investment in Australia

should reach some $30 billion over the

next five years, including the Prelude and

Gorgon LNG projects, and on-going

exploration and feasibility studies in

the country.

From bow to stern, Shell’s FLNG

facility will be 488 metres long, and will

be the largest floating offshore facility in

the world - longer than four soccer fields

laid end to end, the company said.

When fully equipped and with its

storage tanks full, it will weigh around

600,000 tonnes, roughly six times as

much as the largest aircraft carrier. Some

260,000 tonnes of that weight will consist

of steel.

Breakthrough“Our innovative FLNG technology

will allow us to develop offshore gas

fields that otherwise would be too

costly to develop,” said Malcolm Brinded,

Shell’s Executive Director, Upstream

International.

“Our decision to go ahead with this

project is a true breakthrough for the

LNG industry, giving it a significant

boost to help meet the world’s growing

demand for the cleanest-burning fossil

fuel,” he added.

“FLNG technology is an exciting

innovation, complementary to onshore

LNG, which can help accelerate the

development of gas resources,” he said.

The facility has been designed to

withstand the severest cyclones - those of

Category 5.

TechnologySome 110,000 barrels of oil equivalent

per day of expected production from

Prelude should underpin 1.3 MTPA of

condensate and 0.4 MTPA of liquefied

petroleum gas as well as the 3.5 MTPA

of LNG.

The FLNG facility will stay

permanently moored at the Prelude gas

field for 25 years, and in later

development phases should produce from

other fields in the area where Shell has

an interest.

Ann Pickard, head of Shell in

Australia, said: “This will be a game

changer for the energy industry. We will

be deploying this revolutionary

technology first in Australian waters,

where it will add another dimension to

Australia’s already vibrant gas industry.”

Brinded added that “beyond this, our

ambition is to develop more FLNG

projects globally. Our design can

accommodate a range of gas fields, and

our strategic partnership with Technip

and Samsung should enable us to apply it

progressively faster for future projects.

We see opportunities around the world to

work on other FLNG projects with

governments, energy companies and

customers.”

Shell’s decision to make FLNG a

reality has culminated more than a

decade of research and development.

The French-Korean Technip-Samsung

Consortium (TSC) is now proceeding with

the construction of Shell’s first floating

hull for processing LNG.

Detailed design of the facility will be

undertaken by TSC at Technip’s

operating centres in Paris, France, and

Kuala Lumpur, Malaysia, and it will be

built at the SHI shipyard on Geoje island

in Korea.

Technip roleThierry Pilenko, Chief Executive of

Technip, said: “Once again Technip is a

key partner of a visionary customer

pushing back together the limits

of technology.

“This great project is a real

breakthrough for the energy industry

and a true revolution for offshore natural

gas developments.

“Technip is extremely pleased and

proud to bring all the expertise, know-

how and skills of its three business

The Prelude FLNG project offshore north-west Australia will be operated byShell and will be the first of many similar projects in the Asia-Pacific andelsewhere in the world. Prelude will be producing LNG from 2017

p17-25:LNG 3 17/06/2011 09:42 Page 2

segments - Subsea, Offshore and Onshore

- all of which will be instrumental in the

success of Prelude FLNG.

“Within our long-term relationship

with Shell and SHI, we hope that this

project will be the first of many,” Pilenko

added.

The Chief Executive of SHI, In-Sik

Roh said SHI believed the “strength of

the partnership” with Shell and Technip

would lead to success.

Ceremony“We are confident that this project will

help us solidify our position as a clear

leader in FLNG construction and

development,” he said.

The two executives were speaking at a

ceremony in South Korea marking the

advance of the Prelude FLNG project.

Matthias Bichsel, Projects and

Technology director of Shell, pointed out

that Shell’s FLNG team had “drawn on

five decades of expertise in the areas of

LNG technology, LNG shipping and

engineering of offshore floating oil and

gas installations.”

Bichsel added that the consortium

“combines the strengths of each company

to enable the delivery of an integrated

FLNG facility.”

An article written by Barend Pek,

General Manager LNG Front-End

Development for Shell Projects and

Technology, will be presented in full in

the following pages, giving full technical

details and explaining technological

challenges.

Imaginative“Floating liquefaction of natural gas or

FLNG has captured the imagination of

engineers and LNG business developers

ever since it was first considered more

than a decade ago. The concept is simple,

but attractive,” says Pek.

With a number of FLNG technical

hurdles resolved, a decline in new

onshore LNG FIDs, and the difficulty of

finding “easy” gas, FLNG projects have

now gained significant interest.

“This is not a surprise given there is

more than 300 Tcf of natural gas in fields

in the 1-5 Tcf range - a large number of

which are considered uneconomic due to

their size and/or remoteness from shore,

or a limited domestic gas market”

says Pek.

Shell has long been committed to

technology and innovation and is one of

the pioneers of the LNG industry. In the

early 1960s Shell participated in the first

base-load LNG plant, which started up in

Arzew, Algeria.

Shell has ownership in 11 liquefaction

projects currently in operation or

under construction and is a leader in

LNG shipping.

“We also have a proven track record in

marrying production technologies with

offshore environments, successfully

installing the world’s first floating

production storage and off-loading

(FPSO) vessel, the Castellon in Spain

in 1977.

Challenging“We now operate a number of FPSO’s

around the world. Shell has a long

history in creating innovative

technologies to safely and reliably deliver

energy to the world’s markets.

“FLNG technology is challenging, our

investment in design and research over

the last decade shows us this. We believe,

however, that today we have identified

and successfully cleared all technical

show stoppers,” he said.

“Our significant experience in offshore

field development, floating production

facilities, LNG production and LNG

transportation prepares us to be a

pioneer in the development of FLNG.

“FLNG offers a route to greater

flexibility and increased access to natural

gas resources. It also enhances our ability

to operate responsibly in environmental

sensitive areas.

“The market circumstances, the

environmental circumstances, and the

technical maturity let us believe that

FLNG has now grown up to become a

very serious gas monetisation option.

There are numerous other challenges

in FLNG projects, says Pek. His list

includes: finding a suitable field, tuning

the Upstream-FLNG interface, flow

assurance, financing, insurance, partner

alignment, LNG sales, buyers confidence,

classification and certification,

environmental permitting, approval of

safety case, operational setup and

logistics, maintainability, onshore supply

bases, and more.

Combination“In essence FLNG is a combination of the

technologies applied on FPSOs, onshore

LNG plants, and LNG shipping, all three

of these ‘blood groups’ are complex in

themselves, and have their own specific

practices and approaches,” says Pek.

“An amount of effort was spent to

obtain technical alignment over these

interfaces. The available plot space for

the topside facilities is about a factor of 4

smaller as compared to the space

normally occupied for a similar sized

onshore LNG Train.

“The operating plant is effectively

built on top of the cryogenic LNG storage

tanks which gives a series of additional

constraints as compared to an LNG

carrier receiving LNG pumped from

atmospheric storage tanks,” Pek says.

“Furthermore we have learned the

hard way that integration of the different

cultures and practices of the three

different business areas (blood groups) is

as much a challenge as resolving the

technical issues,” he adds.

Lay-outThe design and the lay-out of Shell

FLNG plant is largely safety driven.

Important elements are amongst

others the location of living quarters,

application of safety gaps, ventilation,

design blast pressure profiles, cryogenic

spills, refuge philosophy and risks for

the LNG carrier.

“FLNG has huge potential to extend

the portfolio of traditional LNG concepts

necessary to meet the energy challenge of

the 21st century. Technological and

commercial challenges may have

prevented FLNG succeeding to date, as

evidenced by the fact that there are no

FLNG facilities currently in operation,”

says Pek.

“The market circumstances, the

environmental circumstances, and the

technical maturity lead us to believe that

FLNG has now grown up to become a

very serious gas monetization option,”

he states.

The technical concept of the Shell

FLNG plant, with some of its key

technical challenges, and the inherent

safety approach applied throughout the

design, is described in the article in the

following pages. �

FLNG DEVELOPMENT

LNG journal • June 2011 • 19

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LNG Journal now available electronically

Maritime Content Ltd, 2nd Floor, 8 Baltic Street East, London EC1Y 0UP, UK. Tel: +44 (0)20 7253 2700 Fax: +44 (0)20 7251 9179 wwwlngjournal.com

In this issue:1 LNG import assets in

Italy and Holland give E.ON new optionsLNG Journal, Europe Editor

6 Australia gives bullish outlook for LNG supply to Asia and the

benefits for ChinaLNG Journal Asia-Pacific Editor10 A round-up of latestevents, company andindustry news News index

22 Trends in wholesale gas price formation mechanisms including

inputs of LNG Mike Fulwood, Nexant Global Gas Divisions

26 BG marine expert outlines environment measures for LNG carriers worldwide

Julie A. Nelson, Director, Chartering and Fleet Optimization, BG Group, Houston, Texas, USA

31 Daewoo develops new LNG-fuelled propulsion system for

tanker fleetsYoung Man Lee, Jung Han Lee and Dong Kyu Choi of Daewoo

Shipbuilding & Marine Engineering

34 World Carrier Fleet:Details of LNG vessels

40 Tables of import and export LNG terminalsand plants worldwide

May 2011

44 pagesessential LNGnews!

LNG import assets in Italy and

Holland give E.ON new optionsEurope’s most unique LNG import facility

in terms of technology and commercial

shipping structure is set to begin

operations after the turn of the year.Known as Offshore LNG Toscana

(OLT), the facility is based around an

LNG carrier, the former “Golar Frost”,

converted into a floating storage and

regasification unit.The vessel has been renamed “FSRU

Toscana” and will be permanently

moored just inside the 12-mile limit off

the Tuscan city of Livorno, Italy’s second-

largest Mediterranean port after Genoa.Third facilityThe facility will be Italy’s third LNG

import terminal. The onshore and long-

established Panigaglia facility near Genoa

has been in operation since 1969. It is

owned by Snam Rete Gas, a subsidiary of

Italian energy company Eni.The Porto Levante offshore gravity-

based structure, known as Adriatic LNG,

has been in operation since 2009 and its

shareholders are Qatar Petroleum,

ExxonMobil and Edison Gas.The new OLT facility has Germany’s

E.ON Ruhrgas as a main shareholder.

The German company inherited a

substantial interest in OLT as part of an

asset deal with Endesa of Spain almost

three years ago.It has since brought the facility

towards completion for the 2012-2013

gas year.

The Essen, Germany-based company

has been building up its LNG business in

recent years and by 2012 will have

implemented a strategic spread in its

regasification capacity.

Regas portfolioStefan Buerkle, Chief Operating Officer

for LNG at E.ON, said the “well diversified

regas portfolio” will have access to all

major European gas markets once OLT

enters full operations and the Gate LNG

import terminal in Rotterdam starts up.

E.ON presently operates 2 billion

cubic metres per annum of regas capacity

at the Barcelona and Huelva terminals in

Spain and 1.7 Bcm on the Isle of Grain in

the UK.

Gate LNGThere is also 3 Bcm coming on stream for

E.ON at Gate LNG and the German

company will utilise a significant part of

OLT’s regas capacity to serve its

customer base in Italy from 2012.“The OLT terminal forms a

fundamental part of the E.ON Ruhrgas

regas portfolio and LNG strategy going

forward,” said Buerkle.“The terminal is meant to supply

E.ON’s customers in the Italian market,

be it the end customers, small and

medium enterprises or E.ON’s gas-fired

power plants,” he added.Reflecting on the overall European

LNG market going forward to 2012,

Buerkle said: “While the US seems to be

completely self-sufficient in gas in the

foreseeable future, European buyers, in

spite of the Japan crisis, seem well

positioned to absorb quite some volumes

of LNG originally destined for the US.

“Whilst producers seem to be holding

back a bit for the time being with regard

to long-term deals, spot, short-term and

mid-term deals represent viable options

for both producers and buyers,” he said.

As regards future LNG strategy,

Buerkle said the company was currently

reconsidering its engagement in capital

intensive investment projects under its

new corporate guidelines of “less capital,

more value.”“In order to render liquefaction

ventures bankable, lenders will

continue to require underlying long-

term commitments from both, sellers

and buyers. “Given the increased level of

uncertainty in the global LNG market, it

will be decisive to tailor those long-term

contracts in a way that they will be

robust enough to deliver value for both,

sellers and buyers in an environment of

increased pricing volatility,” Buerkle said.Africa sourceE.ON, in common with other European

LNG players, is looking to the Atlantic

Basin as a future source of new LNG

production projects to come on stream by

LNG Journal, Europe Editor

E.ON’s LNG regasification portfolio is expanding in Europe with new

capacity holdings at terminals in the Netherlands and offshore Italy

age 1

Pho

to c

redi

t: M

ISC

p17-25:LNG 3 17/06/2011 09:42 Page 3

20 • LNG journal • The World’s Leading LNG publication

LIQUEFACTION

Shell’s planned Floating LNG facility will

have a nominal capacity of 3.5 million

tonnes per annum of LNG and more than

4 MTPA for rich feed-gas, plus a

considerable amount of co-produced

liquefied petroleum gas and condensate.

The facility will be capable of

processing gas with a condensate-to-gas

ratio of up to 60 bbl/mmscf.

All reservoir, subsea control,

processing, storage and offloading

systems will be operated from the facility

which will remain on station typically

until the end of the field’s life.

It will also stand up to the severest

weather conditions. This is relevant for

the hurricane-prone Browse region of

North West Australia, the planned site of

Shell’s first FLNG project on the Prelude

and Concerto gas fields.

ConnectionsAll subsea connections join the FLNG

facility via the turret, which is held in

place by up to 24 mooring lines.

The turret enables the FLNG facility

to weather vane around it, remaining at

a fixed position.

Gas and condensate flow from the

reservoir to the facility via a number of

flexible risers, while reservoir carbon

dioxide and produced water can be

reinjected if necessary.

The management of subsea wells and

manifolds is carried out via umbilicals

connected through the turret to the

control room onboard the facility.

Typical flow assurance provisions such

as pigging or methanol and glycol

injection (MEG) are available. The design

has the capability to handle production

disturbances and liquid slugs.

The double-wall substructure carries

the topsides and the turret mooring

system. It hosts the product storage

tankage (220,000 cubic metres for LNG,

90,000 cubic metres for LPG and 126,000

cubic metres for condensate), sufficient to

ensure a highly reliable offtake.

It also carries the power generators,

the water production units (potable

water, process water, and boiler feed

water), waste water treatment facilities

for both urban and process water, and

several facilities for intermediate storage,

maintenance and operations.

The double-wall volume is used for

ballasting with seawater. The living

quarters, the helipad, the control room

and the workshop are located on the aft

of the FLNG hull. Thrusters are installed

to assist the mooring of LNG carriers.

We have chosen a design life of 25

years for the topsides and 50 years for the

substructure, with dry dock and

refurbishment expected after 25 years to

extend the life of the facility.

The topside processing facilities

consist of a single LNG Train, receiving

gas from the rather large well head

separators, with the Shell AdipX process

to remove CO2, mole sieve dryers,

mercury adsorption, a mild LPG

extraction, a liquefaction unit, using the

Shell Double Mixed Refrigerant process

(DMR), at elevated pressure, and an end-

flash unit with a nitrogen rejection

option.

There are also field condensate

stabilisers, a fractionation unit, product

offloading facilities, an LNG vaporiser, a

large flare stack, and optional units for

MEG regeneration/reclaiming, CO2

recompression, and feed-gas compression.

The main compressors and the power

generators are driven by steam

generated in boilers on deck.

A closed cooling water system is

applied to transfer the heat to sea water

using platefin heat exchangers located in

the substructure. The seawater inlet

extends typically 150m below the FLNG

hull.

DesignThe overall availability of the upstream,

processing and the product offloading

facilities is essential to obtain a robust

project.

Accordingly a series of availability

studies for different elements of the chain

have been performed optimising the

hardware line-up and sparing.

For upstream and FLNG we could

largely build on existing knowledge,

while paying special attention to “close

coupling” of the FLNG facility and the

wells.

Close coupling means that the

traditional buffer capability of

transmission lines is not present and

extensive dynamic modelling was

performed to understand this in depth.

For offloading, including the mooring

of carriers, extensive work has to be done.

Based on extensive studies and

enhancements to the design, we expect

an overall availability equivalent to a

land-based facility.

OffloadingThe sheltered locations for offloading

applied in onshore plants, for example by

a breakwater, is not applicable for an

FLNG plant.

One has to accept the metocean

conditions as they come. An additional

complication is the difference in elevation

between the carrier and FLNG deck

which is much higher in the case of the

Shell FLNG hull.

For LNG and LPG side-by-side loading

is selected. Intensive work has been done

to develop dedicated mooring procedures

for LNG and LPG carriers alongside the

FLNG plant. In some cases thrusters

assistance is needed to ensure proper

mooring.

We have been involved in detailed

evaluations of systems, including basin

tests to quantify the movements between

the vessels and defining the required

operating envelopes for the offloading

systems.

More detailed work on mooring

requirements and side-by-side offloading

has progressed in the meantime. The

condensate will be offloaded stern-to-bow

using floating hoses.

The movement of the FLNG hull may

cause sloshing or maldistribution in

process equipment. These phenomena

have been investigated in house and by

several other parties.

These results led to the selection of

packed rather than trayed columns for

fractionation, stabilisation, and gas

treatment.

The spiral wound heat exchangers

applied in the liquefaction process need

additional precautions to obtain reliable

performance.

The design of liquid distributors in

columns and heat exchangers needed

special attention to ensure robust

operation. Interfaces in columns, vessels

and boilers needed some precautions to

suppress sloshing.

Beyond process performance one

also needs to ensure that fatigue,

potentially caused by the continuous

movement, and recognising the

mechanical flexibility in the FLNG hull,

is properly understood.

Cyclone conditionsThe Shell FLNG plant is designed to

remain on station for 25 years, including

in cyclone conditions. Extensive analysis

of metocean conditions, looking at the

FLNG vessel dynamics and turret

mooring, including extensive model

testing, has been undertaken to convince

ourselves and other major stakeholders

on the robustness of this approach.

A model of 8 metres length and

FLNG technical challenges addressed as Shell reveals game plan for stranded gasBarend Pek, General Manager LNG Front End Development, Shell Projects and Technology

Figure 1: Production capacity versus LNG HHV, at constant power input

p17-25:LNG 3 17/06/2011 09:42 Page 4

weighing about 4.5 metric tonnes was

used in basin tests at Marin’s test

facilities in The Netherlands.

Non co-linear behaviour was

extensively assessed. The dynamic

behaviour of the huge FLNG hull is mild

compared to typical FPSOs in similar

metocean conditions.

The survival conditions effect the

design of the substructure, the structural

steel in the topsides, and the turret

mooring system which will be the largest

ever build.

ConsiderationsThe liquefaction unit is the heart of the

topside facilities, and represents the most

expensive unit. The Propane Mixed

Refrigerant process is the workhorse of

the LNG industry.

It is, however, less suitable for

application in an FLNG plant because

the large kettles have a high propane

content and need a large plot size.

We consider nitrogen expansion cycles,

having an inherent lower efficiency, to be

more suitable for small-scale

applications.

Shell has chosen to apply a single

Train using Shell’s Double Mixed

Refrigerant (DMR) process. This process

has been used very successfully on the

Sakhalin II project in the Russian Far

East that started up in March of 2009.

The DMR process provides a low

equipment count, low plot space and it

has a relatively low inventory of

refrigerant.

Selecting a single Train results in a

lower equipment count, capital

expenditure and plot space compared

with multiple Trains.

Generally gas turbines are selected to

drive the main refrigerant compressors

and a large number of existing LNG

Trains are steam driven. Electrical

driven systems are not widely applied in

LNG plants.

The choice for the refrigerant drivers is

not trivial in the case of the FLNG

project. Here are some of the challenges:

� The high CO2 content of feed-gas and

condensate content of the feed-gas

ask for reboiler duties around 200

MW. As heat transfer medium one

could select a heat transfer fluid,

warm water, or steam. For this scope

steam gives the lowest size and

weight of heat exchangers and

topsides piping.

� The FLNG facility is located above

the field, which implies that any

disturbances in the upstream are felt

immediately on the processing

facility, and disturbances on the

topsides can lead to flaring. This

“close coupling” represents an

important difference with onshore

plants where the trunklines can be

used as buffer (varying pressure) to

decouple the upstream facilities from

the LNG plant. In some cases the flow

assurance method requires

depressuring the upstream flowlines

- and a lengthy re-start period - upon

a disturbance of the FLNG facility.

This implies that reliability of the

single Train topsides is very

important in order to secure a high

availability.

� Being offshore the maintenance and

service works are more expensive as

compared to onshore plants, and for

example replacing major equipment

items at site in some cases is not

always feasible. Accordingly it is

important to use components with

proper track records and to keep

systems simple and robust.

Additionally our experience shows that

the occurrence of damage and leaks in

cryogenic equipment is often connected to

the number of plant trips.

We have considered steam drives, gas

turbines and electrical driven plants. The

earlier work was based on electrical-

driven machinery, enabling the

installation of very reliable process

drivers and reliable power supply by

providing sparing in the power plant.

However, after several studies we have

concluded that these systems are very

complex, costly, and call for a lot of plot

space.

Comparing gas turbines with steam

systems our experience shows that the

number of trips of steam driven plants is

a factor of 5 to 10 lower as compared to

gas turbine driven plants. The overall

capital cost of both systems are similar,

with steam systems calling for higher

operator attention.

Gas turbine driven plants clearly have

higher thermal efficiencies as compared

to steam systems, but the experience of

large capacity gas turbines for offshore

applications is limited.

Taking all considerations into account,

weighted towards robustness and

reliability, we have chosen for a system

with high pressure steam generation.

The steam will drive the main

compressors and the power generators.

Despite the lower efficiency of the steam

system we find that the overall efficiency

from well to LNG offloading is still very

good when compared to traditional

integrated schemes.

Availability of cold deep sea cooling

water, a liquefaction process with an

excellent efficiency, and the absence of

long pipeline to shore contribute to this.

LPG extractionClearly to minimise equipment count

(and cost) it would be preferable to avoid

LPG export and produce richer LNG

instead.

However, the HHV of the LNG

produced from some of our lead prospects

would be above 1225 btu/scf without LPG

export, and this leads to installation of

LPG export possibilities to prevent price

penalties for HHV higher than the

normal trading range.

The additional space required for LPG

storage is significant and slightly more

complex fractionation facilities are

required, but overall this is justified.

For LPG export there is the

opportunity to optimise utilisation to

maximise the revenue in the operational

phase.

The design allows mild LPG

extraction, but equally richer LNG can be

produced with more or all LPG left in the

LNG.

The power input is kept constant but

operating conditions of extraction

columns and liquefaction unit are

optimised for each chosen HHV. In

practice this can be achieved by

installation of Advanced Process Control.

For this (rich) gas composition there is

maximum production when HHVs

around 1100 are selected.

For higher HHVs the amount of power

required to cool the LPG components to

LNG temperature rather than their own

atmospheric boiling point leads to a

reduced capacity.

For the lower HHV’s the energy

required for the fractionation reduces the

resulting throughput.

LNG containmentWe have chosen membrane-based LNG

containment systems licensed by GTT.

The alternative of the spherical Moss

tanks would have a lower utilisation of

the volume in the substructure.

SPB (Self Supporting Prismatic Tank

IMO type B) tanks have been discarded

because of cost and schedule

disadvantages. Moreover they have far

fewer applications in the LNG industry.

Sloshing is recognised as a risk, and a

wide range of studies have been

performed to understand this thoroughly

and we feel confident to apply this

technology.

The geometry of the containment

tanks is chosen such that sloshing is not

expected for the locations considered.

However, reinforcement is applied to

ensure that LNG will be contained in the

unexpected case that sloshing would still

occur.

Furthermore, there is a system of tank

level management for cases where

extreme conditions would occur. The

installation of two rows of containment

tanks also allows for a central bulkhead

which is useful to obtain the necessary

strength of the substructure and to

provide central support for the topside

modules.

Intake systemThe Floating LNG facility requires about

50,000 m3/hour of water taken from a

depth of about 150-200m below sea level

Figure 2: Liquefaction will be by the Shell Double Mixed Refrigerant process

LIQUEFACTION

LNG journal • June 2011 • 21

p17-25:LNG 3 17/06/2011 09:42 Page 5

22 • LNG journal • The World’s Leading LNG publication

LIQUEFACTION

so as to reach water of low temperature.

To this end, a water intake riser

assembly is installed underneath the

FLNG hull to pump up and convey the

cold water upward to a series of platefin

heat exchangers where the rejected heat

from the topsides is picked up before it is

disposed in the sea again.

For a weather-vaning vessel a riser

system can be attached to the seabed

only if the risers come up through the

turret.

There is insufficient space in the

turret to channel these large volumes of

cooling water through the turret, and

therefore it was chosen to use free

hanging risers. To avoid a large footprint

on main deck, a free hanging bundled

riser solution was developed in which the

risers are installed very close to each

other.

The matured riser concept consists of

nine risers located in an array of three by

three. Each riser has a diameter of

approximately 1.0m.

The key features of the concept are:

(1) The creation of a flexible load transfer

at the interface between the riser and

the underside of the hull so that

vessel motions do not impose high

bending stresses on the risers;

(II)Use of a guide sleeve (or riser spacer)

which enables creation of a riser

bundle whereby the risers are spaced

very closely together but are

prevented from colliding with each

other.

The eight water intake risers at the

periphery of the riser bundle aspirate

and convey cooling seawater. Each water

intake riser consists of approximately 12

metre-long plain steel pipe sections

assembled together using a pin-and-box

type premium Merlin connector.

The structural riser, located in the

middle of the bundle, does not convey

cooling water. Its function is mainly to

support the spacers. The spacer provides

only horizontal restraint to the risers.

Vertical relative movement and

rotation of the risers are not constrained.

This is achieved by leaving a small gap

(about an inch radial) between the water

intake risers and the spacer.

The water intake risers and the

structural riser are suspended from the

FLNG hull by means of a Shell-patented

riser hanger assembly.

The main purpose of the riser hanger

assembly is to minimize dynamic loading

on the risers by decoupling the rotations

of the barge and the riser, i.e. provide a

pin joint. This is achieved by combining a

rubber flexible hose, whose function is to

provide the flow conduit, with an internal

suspension chain whose function is to

carry the axial load.

Above the riser hanger assembly, an

electrical submersible seawater lift

pump, one per water intake riser, is

located inside the caisson.

The riser concept described was

developed and matured within Shell. It

was proven that the riser bundle had

sufficient margin to survive the 10,000

year cyclone events. It appeared that the

riser bundle design was more governed

by fatigue requirements rather than

strength requirements.

It was unclear whether vortex-induced

vibration (VIV) of the riser bundle would

occur and whether it would contribute to

fatigue damage.

In a current, a single, bare riser might

vibrate out of plane due to

synchronization with the vortex shedding

along the length of the riser, when the

shedding frequency of the vortices

coincides with one of the natural periods

of the riser.

However, the VIV of a riser bundle, in

particular the influence of the spacers

and the effect of the

closely-spaced

risers were

unknown;

it was

unclear

whether

the risers in

the bundle would

vibrate synchronously

or whether individual riser

would vibrate independently.

To understand the VIV behaviour

of the riser bundle, two test

campaigns at scale 1 to 50 were

performed at Shell’s Westhollow

Research Centre in Houston.

The VIV response of the bundle was

tested by gradually increasing the

current velocity in the tank. The main

result from this experiment was that the

bundle in a current behaves as one

structure, i.e. all nine pipes vibrate

simultaneously.

Since fatigue of the riser bundle

appeared to be the governing design

parameter, it was decided to try to

eliminate fatigue damage due to VIV.

Shell invented an optimized

suppression methodology by equipping

helical strakes on the four corner risers.

The experiments proved that VIV of the

riser bundle, with

strakes on

the

corners,

was

completely

suppressed.

ConclusionShell’s approach to FLNG is to

design for safety, longevity,

applicability over a wide range of

anticipated feed-gas compositions

and metocean conditions and for

high reliability and availability.

The development of FLNG plant is

complex and we have invested

considerable time and money to put

ourselves at the forefront of this

technology.

We believe that our 45 plus years of

experience in LNG technology, LNG

shipping and offshore operations, provide

us with a sound launch pad for

commercializing and applying floating

liquefaction technology.

With the Shell FLNG FEED worked

by Technip and Samsung from August

2009 and shipping, and with the Prelude

and Concerto gas discoveries, located in

the Browse Basin, we are progressing our

proposed design for a large-scale floating

liquefaction solution.

We work closely with the Australian

regulator on obtaining the necessary

permits, certifications and approvals. And

we were very pleased that Federal

environmental approval was obtained

in November 2010 for our Prelude project.

We wish to acknowledge the

contribution of very many colleagues,

predecessors and partners for all the

hard work and creative effort spent in

the development of the Shell FLNG

technology. �

References

1. “World Energy Outlook 2010”, International Energy Agency

2. “Floating LNG Solutions from the Drawing Board to Reality”, Faber F et al., Offshore Technology Conference, Houston, 2002

3. “Sakhalin Energy’s initial operating experience from simulation to reality: Making the DMR process work ”, Verburg R et al.,LNG16, Oran, 2010

4. “Mooring of LNG Carriers to a

Weather vaning Floater – Side-by-Side or Stern-to-Bow ”, van der Valk C et al., Offshore Technology Conference, 2005

5. “Safety Drivers in the Lay-out of Floating LNG Plants”, Persaud M et al., 2003 AIChE Spring National Meeting: LNG & Gas Transportation Sessions.

6. “Floating LNG: Shell’s recent history and current approach” Gilmour N et al., LNG16, Oran,

20107. “Next generation onshore LNG

plant designs”, van Loon M et al. Gastech , Amsterdam, 2011

8. “Chicksan LNG Marine loading arms enhanced for application in exposed areas ” ,van der Valk C et al.,LNG14, Doha, 2004

9. “A step change in LNG operations through Advanced Process Control”, den Bakker K et al., World Gas Conference, 2006

...our 45 plus years ofexperience in LNG

technology, LNG shippingand offshore operations,provide us with a sound

launch pad forcommercializing and

applying floatingliquefaction technology.

p17-25:LNG 3 17/06/2011 09:42 Page 6

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p17-25:LNG 3 17/06/2011 09:43 Page 7

24 • LNG journal • The World’s Leading LNG publication

LNG EQUIPMENT

Extruded low-finned and dual-enhanced

tubes are an established heat transfer

enhancement technology used for

decades in multiple industries such as

the heating, automotive, air-conditioning

and refrigeration industries as well as

the power and hydrocarbon sectors.

Over the last 15 years, France’s

Technip and Germany’s Wieland have

collaborated to qualify dual-enhanced

tubes with the aim of becoming a

hydrocarbon processing industry

standard, especially for large shell-and-

tube heat exchangers for grassroots LNG

and ethylene plants.

Starting in 1996 a joint academia-

industry R&D program funded by the

European Union was formed,

establishing heat transfer and thermal

design information for enhanced

horizontal shell-side nucleate boiling

with light hydrocarbons, primarily

propane.

Further work packages concentrated

on enhanced tube-side heat transfer and

pressure drop performance in single-

phase gas and liquid service as well as

two-phase condensation.

This created a solid design basis

allowing compact and efficient enhanced

heat exchanger designs.

Industrial references have been

established from 2000 onwards for

thermosiphon, kettle reboiler and chilling

services in polypropylene, ethylene and

LNG plants - first in debottlenecking and

more recently in grassroots applications.

Dedicated preservation guidelines for

the whole supply chain from tube

fabrication, heat exchanger assembly,

transportation and storage up to start-up

have been developed and project proven

in order to guarantee proper operation.

We will look at the implementation of

dual-enhanced tubes in the hydrocarbon

processing industry from debottlenecking

to grassroots, demonstrating constant

and stable performance over the years in

accordance with expectations.

Applications for extruded low-finned

(LF) and dual-enhanced tubes are

widespread in multiple industries, ranging

from the air-conditioning and refrigeration,

heating, automotive, power as well as the

hydrocarbon processing industry.

A few selected examples are:

� Dual-enhanced boiling and

condensation tubes for packaged

chillers

� Inner-grooved tubes for coil heat

exchangers in the air-conditioning

industry

� Dual-enhanced tubes for the

hydrocarbon processing industry

� Dual-enhanced tubes for power

steering oil cooling in the automotive

industry

For the hydrocarbon processing industry

distinct dual-enhanced tubes for boiling

and condensing, as well as single-phase

heat transfer services have been derived

from standard LF tubes.

A wide range of proven references of

both LF and dual-enhanced tubes have

existed in the hydrocarbon processing

industry for decades, ranging from

refining, petrochemical, chemical and gas

processing applications.

Standard tube materials are carbon

and low-temperature carbon steels, but

solutions are also available in low-alloy

carbon steel as well as stainless steel and

titanium.

Over the last decades Wieland has

developed an outstanding record of key

applications with dual-enhanced tubes.

Combining this innovative heat-

transfer technology from Wieland with

world-scale engineering, procurement and

construction from Technip resulted in

highly attractive enhanced heat-transfer

solutions allowing for more compact and

efficient heat-transfer equipment, as well

as lower investment costs.

ResearchSince 1996 Technip and Wieland have

been collaborating in the development of

a new dual-enhanced nucleate boiling

tube, called GEWA-PB.

During two joint industry and academia

research projects, JOULE III and AHEAD,

funded by the EU, fundamental research

and qualification was conducted.

Key activities have been the

development and characterization of

enhanced shell-side nucleate boiling

structure, especially at low-temperature

approaches, as well as tube-side

enhancement structure for both single-

phase gas and liquid as well as two-phase

condensate heat transfer.

The different steps from lab-scale

testing to industrial application stretched

over a period of around 10 years.

The thermal advantage of the GEWA-

PB tube with shell-side boiling propane

versus a plain tube is between a factor 2

and 3 of the boiling heat-transfer

coefficient.

Together with an improved tube-side

performance ranging between a factor 1.6

to 2.4, depending on single-phase and

two-phase flow conditions, the overall

heat-transfer benefit leads to overall

success.

The key benefit of the GEWA-PB tube

is the capability of a superior operation

at low temperature approaches down to

2°C and below where standard plain or

LF tubes are no longer suitable.

In various schemes and applications,

benefits can be:

� Size reduction

� Reduction of number of heat

exchangers per unit

� Capacity increase resulting from

improved efficiency

The Technip Heat Transfer Engineering

Dept. incorporated the GEWA-PB tube in

industrial reboiler applications such as

for thermosiphon and kettle-heat

exchangers.

Special attention was given both to the

thermal and mechanical design along

with an improved kettle design such as:

� Proper fluid distribution at inlet and

outlet

� Verification of liquid entrainment,

especially for suction line to

compressor

Thermal design tools from Heat Transfer

Research Inc. (HTRI) as well as

Enhanced-Heat Transfer (EHT) software,

developed by John Thome and licensed to

HTRI software are used as convenient

thermal design tools for enhanced heat-

transfer solutions.

In a similar way to the enhancement

of reboilers, enhanced heat-transfer

solutions have been developed for

horizontal condensers, with shell-side

condensing propane or propylene

refrigerant and tube-side cooling water.

Designs are typically with TEMA type

X- or alternatively E-shell. A typical

solution is with a dual-enhanced GEWA-

KS tube having a shell-side LF structure

in combination with an internal helical-

fin structure.

These enhanced heat-transfer

technologies have been made available

and qualified for horizontal shell-and-

tube type reboilers and condensers

within key business areas of Technip

such as for LNG and ethylene plants.

The pre-requirement for the time

being in these applications is for clean

refrigerant and process fluids.

Further studies are required for

investigating the suitability of dual-

enhanced tubes for operating conditions

with fouling tendencies.

For base-load LNG plants, using the

Dual-enhanced tubes prove durable and stable performers for LNG processingThomas Lang, Wieland-Werke AG, Ulm, Germany, and Brigitte Ploix, Technip, Paris, France

Figure 1: The C3/MR liquefaction process overview. GEWA-PB tube in C3 Ref.chilling trains for NG and MR and GEWA-KS tube in C3 Ref. condenser

p17-25:LNG 3 17/06/2011 09:43 Page 8

LNG EQUIPMENT

LNG journal • June 2011 • 25

C3/MR process licensed by Air Products,

the enhanced heat-exchanger

technologies are highly attractive within

the propane pre-cooling cycle.

The major application for enhanced

GEWA-PB boiling tubes is within the

main propane refrigerant chilling train

with cooling/condensation of natural gas

(NG) or mixed refrigerant (MR) on the

tube-side and propane refrigerant boiling

on the shell-side.

The primary application of the

enhanced GEWA-KS condensation tube

is for the propane refrigerant condenser

with shell-side propane refrigerant

condensing and tube-side cooling water.

For ethylene plants enhanced heat-

exchanger solutions are available for the

majority of reboiler and condenser heat

exchangers in the cold section, such as

the C2 and C3 fractionation and splitting

services, as well as the refrigerant units.

Case studiesThe performance of GEWA-PB and

GEWA–KS tubes is demonstrated in two

representative cases, both for a propane

refrigerant chiller and condenser in

comparison to standard plain and LF

tubes.

The cases are taken from the

application in the Qatar LNG mega-

Trains, with the C3/MR process design

licensed by APCI including nitrogen sub-

cooling cycle, having a nominal capacity

of 7.8 million tonnes per annum of LNG.

In both cases substantial size and

weight reduction can be achieved by

using dual-enhanced tubes.

Especially for such large equipment

the benefit becomes evident when

considering the whole supply chain,

ranging from fabrication, transportation

as well as plant aspects covering

installation, operation and maintenance.

A detailed technico-economic study by

Technip of the two chilling trains for NG

and MR, showed very attractive savings

in capital expenditure, plot space as

well as capabilities for efficiency

improvements, or vice versa an attractive

opportunity for capacity increase.

For the standard cold approach of 3K,

the GEWA-PB allows for a CAPEX

reduction of 20 percent versus a solution

with standard LF tubes, and at the same

time a reduction of the plot space of 26

percent.

In the case of the reduced cold

approach with 2K, the compression

power is reduced by around 2.2 percent,

translating into about 1 percent

additional LNG capacity.

The additional annual income,

depending on the LNG price, is far

superior compared to the overall cost of

the chilling train.

It has to be noted that the case with

the GEWA-PB tube and 2K cold approach

is, with 16 percent plot space reduction,

still more compact and with the same

CAPEX, so it’s not more expensive

compared to the LF case with a 3K cold

approach.

This study is based on an LNG plant

with 6.5 MTPA LNG nominal capacity.

Both solutions with LF and GEWA-PB

tubes has been analysed for the two

chilling trains such as: Propane/MR

chilling train and propane/NG chilling

train. Each train is operating at four

propane levels.

For the GEWA-PB enhanced boiling

tube a reduction of the cold approach to

2K is feasible and considered by Technip

for improved LNG plant designs.

The following items have been

considered for the CAPEX: heat

exchanger, piping, steel structure, piping

and exchanger foundation.

LNG PlantIn 2003, the GEWA-PB tube was applied

for the first time in an LNG plant as part

of the Qatargas debottlenecking project

(QDN).

The objective was to expand the

capacity of the existing three Trains from

2 MTPA to 3 MTPA per Train.

The project comprised the replacement

of various propane refrigerant

compressors, gas turbine drivers, drums

as well as the LP propane/MR chiller.

A new kettle-type chiller equipped

with GEWA-PB tubes, with tube OD of

5/8”, was successfully installed in each of

the three Trains.

Test runs following the start-up of

Train 2 in 2003, Train 3 in 2004 and

Train 1 in 2005 confirmed the thermal

and hydraulic tube performance.

For Train 3, the performance was

verified again in 2007, confirming stable

performance, without degradation due to

fouling.

Qatargas is very satisfied with the

overall performance of these chillers.

Although the actual operation point did

deviate from the actual design point, the

overall heat-transfer coefficient is

maintained stable.

In addition, a very low cold average

approach temperature of 1.4 K between

tube-side condensing MR and shell-side

boiling propane is confirmed,

demonstrating the superior performance

of the GEWA-PB tube.

Building on the success of QDN,

Technip applies GEWA-PB tubes for all

large LNG and ethylene projects.

The enhanced performance provides

clients with technical and economical

attractive solutions.

Technip and its joint venture partner

Chiyoda of Japan have engineered and

built six LNG Trains at the Ras Laffan

LNG complex in Qatar, with annual LNG

capacity of 7.8 MTPA per Train.

Of the six Trains now operating, two

are for Qatargas II, two for RasGas III,

and one each for QatarGas III and

Qatargas IV.

PreservationAs part of the market introduction of

dual-enhanced GEWA-PB and GEWA-KS

tubes Wieland developed together with

vendors and operators a guideline for the

proper preservation of the tubes from

fabrication to operation.

The experience of all parties has been

brought together. An important feature

during fabrication is, for example, the

proper cleaning and degreasing, especially

for the enhanced boiling structure,

preventing any performance degradation.

A thorough preservation program

along tube and heat-exchanger

transportation, heat-exchanger assembly

and storage on-site is essential, especially

for bridging long-term storage periods.

Also for maintenance activities during

operation suitable preservation actions

have been proposed.

ConclusionsTechnip and Wieland have worked

successfully over the past 15 years in

developing and introducing enhanced

heat-transfer technologies using dual-

enhanced tubes, both GEWA-PB and

GEWA–KS, that are fast becoming

standard solutions for certain key heat

exchangers in LNG and ethylene plants.

The enhanced heat-transfer technology

is based on experienced thermal design

and equipment engineering.

Along with field data validation, the

superior performance is confirmed and a

safe transition from revamp to grassroots

projects has been realized, with more

than 50 enhanced heat exchangers

supplied in the last 10 years.

Together with the qualification of the

enhanced heat-transfer technologies the

preservation of the dual-enhanced tubes

along the supply chain has been

established.

Thereby all steps from the tube

fabrication, transportation, assembly of

the heat exchanger, including start-up

and operation of the equipment in the

plant, are covered.

The technology is made available to

clients through the projects of Technip

and in most cases third parties. �

Figure 2: Enhanced tube preservation from fabrication to operation for LNG

References[1] Webb L. Ralph, Principles of

Enhanced Heat Transfer, John Wiley & Sons, 1994

[2] Thome J., Heat Transfer Augmentation of Shell-and-Tube Heat Exchangers for the Chemical Processing Industry, 2nd European Thermal-Sciences and 14th UIT National Heat Transfer Conference, Rome, May 29-31, 1994

[3] Thonon B., Advanced and High-Performance Heat Exchangers for the Hydrocarbon Processing

Industry, Heat Transfer Engineering, 28(5), pp. 73-84, 2005

[4] Thonon B., J.J. Delorme, Enhanced Reboilers for the Process Industry, Engineering Foundation Conference, Davos, July 2001

[5] Rabeau P., H. Paradowski, J. Launois, How to reduce CO2 Emissions in the LNG Chain, LNG15 Conference, Barcelona, 2007

[6] Heat Transfer Research Inc., 150 Venture Drive, College Station, TX 77845, USA

p17-25:LNG 3 17/06/2011 09:43 Page 9

26 • LNG journal • The World’s Leading LNG publication

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Al Kharaitiyat 216,200 QGTC STASCO Hyundai May-09 Liberia DRL TZ Mk. III 4 Qatargas III Qatar-Atlantic

Al Kharaana 210,000 QGTC Stasco Daewoo Oct-09 Marshall I. DRL GT NO 96 4 Qatargas IV Qatar-Atlantic

Al Kharsaah 217,000 Teekay Teekay Samsung May-08 Bahamas DRL TZ Mk. III 4 Qatar-various RasGas III

Al Khaznah 135,500 National Gas National Gas Mitsui Chiba Jun-94 Liberia S Moss 5 Abu Dhabi-Japan ADGAS 2020

Shipping Shipping

Al Khor 137,350 J4 Consortium NYK Line Mitsubishi Dec-96 Japan S Moss 5 Qatar-Japan Qatargas 2022

Nagasaki

Al Khuwair 217,000 Teekay LNG Teekay LNG Samsung July-08 Korea DRL TZ Mk. III 4 Qatar-Atlantic Basin RasGas 2033

Al Mafyar 216,200 OSG/Nakilat OSG/Nakilat Hyundai Oct-07 Marshall I DRL TZ Mk. III 4 Qatar/UK/Var. Qatargas II 2032

Al Marrouna 151,700 Teekay Teekay Daewoo Nov-07 Bahamas S GT NO 96 Qatar-Europe Ras Gas I 2031

Al Mayeda 266,000 QGTC Stasco Samsung Jan-09 Liberia DRL TZ Mk. III 5 Qatargas III Qatar-US/Var.

Al Rayyan 135,360 J4 Consortium K Line Kawasaki Mar-97 Japan S Moss 5 Qatar-Japan Qatargas 2022

Sakaide

Al Rekayyat 216,200 QGTC STASCO Hyundai June-09 Liberia DRL TZ Mk.III 4 Qatargas III Qatar-Atlantic

Al Ruwais 210,100 ProNav ProNav Daewoo Nov-07 Germany DRL GT NO 96 4 Qatar-UK Qatargas II 2032

Al Sadd 210,100 Naklilat Stasco Daewoo Mar-09 Liberia DRL GT NO 96 4 Qatargas III Qatar-Atlantic Basin

Al Safliya 210,100 ProNav ProNav Daewoo Dec-07 Germany DRL GT NO 96 4 Qatar-UK Qatargas II 2032

Al Sahla 216,200 J5 MOL Hyundai Jun-08 Japan DRL TZ Mk. III 4 Qatar-Atlantic Basin Ras Gas III

Al Samriya 261,700 QGTC STASCO Daewoo Sept-08 Marshall I DRL GT NO. 96 5 Qatar-Atlantic Basin Qatargas II

Al Shahaniya 210,100 Nakilat Stasco Daewoo Feb-09 Liberia DRL GT NO 96 4 Qatargas III Qatar-Atlantic Basin

Al Shamal 217,000 Teekay LNG Teekay LNG Samsung June-08 Qatar DRL TZ Mk. III 4 Qatar-Atlantic Basin RasGas 2033

Al Thakhira 145,000 Peninsular LNG K Line Samsung Sep-05 Luxemb'g S TZ Mk. III 4 Qatar-Italy Qatargas 2031

Al Thumama 216,000 J5 Consortium MOL Hyundai April-08 Japan DRL TZ Mk. III 4 Qatar/Japan Rasgas 2028

Al Utouriya 215,000 J5 MOL Hyundai Sept-08 Panama DRL TZ Mk. III 4 Qatar-Atlantic Basin RasGas 2033

Al Utourma 215,000 J5 MOL Hyundai Sept-08 Panama DRL TZ Mk. III 4 Qatar-Atlantic Basin Ras Gas III

Al Wajbah 137,350 J4 Consortium MOL Mitsubishi Jun-97 Japan S Moss 5 Qatar-Japan Qatargas 2022

Nagasaki

Al Wakrah 135,360 J4 Consortium MOL Kawasaki Dec-98 Japan S Moss 5 Qatar-Japan Qatargas 2022

Sakaide

Al Zhubarah 137,570 J4 Consortium MOL Mitsui Chiba Dec-96 Japan S Moss 5 Qatar-Japan Qatargas 2022

Alto Acrux 147,000 LNG Marine NYK Line Mitsubishi Mar-08 S Moss 4 Various/Japan

Transport

Aman Bintulu 18,928 Perbadanan/ Perbadanan NKK Tsu Oct-93 Malaysia S TZ Mk. III 3 Malaysia - Japan Petronas 2013

NYK Line NSL

Aman Hakata 18,800 Perbadanan/ Perbadanan NKK Tsu Nov-98 Malaysia S TZ Mk. III 3 Malaysia - Japan Petronas 2017

NYK Line NSL

Aman Sendai 18,928 Perbadanan/ Perbadanan NKK Tsu May-97 Malaysia S TZ Mk. III 3 Malaysia - Japan Petronas 2017

NYK Line NSL

Annabella 35,500 Chemikalien Chemikalien La Seyne May-75 Liberia S GT NO 82 5 Libya-Spain Sirte Oil

Seetransport Seetransport

Arctic Discoverer 140,000 K Line K Line Mitsui Chiba Jan-06 Bahamas S Moss 4 Norway-US Statoil 2036

Arctic Lady 147,200 MOL/Hoegh LNG Hoegh LNG Mitsubishi Apr-86 Norway S Moss 4 Norway-U.S. Petronas 2017

Nagasaki

Arctic Princess 147,200 MOL/Hoegh LNG Hoegh LNG Mitsubishi Jan-06 Norway S Moss 4 Norway-US Suez LNG 2035

Nagasaki

Arctic Sun 89,880 Arctic LNG Marathon IHI Chita Dec-93 Liberia S IHI SPB 4 Alaska - Japan ConocoPhillips 2014

Shipping /Marathon

Arctic Voyager 140,000 K Line K Line Kawasaki Jul-06 Bahamas S Moss 4 Norway-Spain-US Statoil 2026

Bachir Chihani 129,750 SNTM-Hyproc SNTM-Hyproc La Seyne Feb-79 Algeria S GT NO 85 5 Algeria - Turkey Sonatrach 2015

Banshu Maru 125,542 J3 Consortium K Line Mitsubishi Oct-83 Japan S Moss 5 Indonesia-Japan Pertamina 2011

Nagasaki

World LNG Carrier FleetLNG Capacity Owner Operator Builder Delivery Flag Power Cargo No. of Regular Exporter Contract

carrier m3 Date Plant System tanks Route

p26-31:LNG 3 17/06/2011 09:46 Page 2

LNG journal • June 2011 • 27

CARRIER FLEET

Barcelona Knutsen 173,400 Knutsen Knutsen Daewoo May-10 N.I.S. DFDE GT NO 96 4 Repsol LNG

Bebatic 75,060 Brunei Shell STASCO Atlantique Oct-72 Brunei S TZ Mk. I 6 Brunei-Japan Brunei LNG 2013

Tankers

Bekalang 75,080 Brunei Shell STASCO Atlantique Jun-73 Brunei S TZ Mk. I 6 Brunei-Japan Brunei LNG 2013

Tankers

Bekulan 75,070 Brunei Shell STASCO Atlantique Dec-73 Brunei S TZ Mk. I 6 Brunei-Japan Brunei LNG 2013

Tankers

Belais 75,040 Brunei Shell STASCO Atlantique Jul-74 Brunei S TZ Mk. I 6 Brunei-Japan Brunei LNG 2013

Tankers

Belanak 75,000 Brunei Shell STASCO La Ciotat Jul-75 Brunei S TZ Mk. I 5 Brunei-Japan Brunei LNG 2013

Tankers

Ben Badis 177,000 MOL MOL Hyundai Oct-09 Panama DFDE TZ Mk. III 4 Various

Berge Arzew 138,088 BW Gas BW Gas Daewoo Jul-04 Norway S GT NO 96 4 Exports from Algeria Sonatrach 2030

Berge Boston 138,059 BW Gas BW Gas Daewoo Jan-03 Norway S GT NO 96 4 Atlantic LNG Suez LNG 2032

Berge Everett 138,028 BW Gas BW Gas Daewoo Jun-03 Norway S GT NO 96 4 Atlantic LNG Suez LNG 2033

Bilbao Knutsen 138,000 Knutsen/ Knutsen/ IZAR Sestao Jan-04 Spain S GT NO 96 4 Trinidad - Spain Atlantic LNG 2024

Marpetrol Marpetrol

Bilis 77,730 Brunei Shell STASCO La Seyne Mar-75 Brunei S GT NO 82 5 Brunei-Japan Brunei LNG 2013

Tankers

Bishu Maru 125,000 J3 Consortium K Line Kawasaki Aug-83 Japan S Moss 5 Ind’sia-Japan Pertamina 2011

Sakaide

Bluesky 145,700 Stena Stena Daewoo Jan-06 Panama S GT No 96 4 Various

British Diamond 155,000 BP Shipping BP Shipping Hyundai Sep-08 IOM DFDE TZ Mk. II 4 Tangguh LNG Indonesia-Various

British Emerald 155,000 BP BP Hyundai Jun-07 UK DFDE TZ Mk. III 4 Ind’sia-Japan Tangguh LNG 2033

British Innovator 138,200 BP Shipping BP Shipping Samsung Jul-03 Isle of Man S TZ Mk. III 4

British Merchant 138,000 BP Shipping BP Shipping Samsung Apr-03 Isle of Man S TZ Mk. III 4 Engas 2007

British Ruby 155,000 BP Shipping BP Hyundai Jan-08 U.K. DFDE TZ Mk. III 4 Various

British Sapphire 155,000 BP Ships BP Ships Hyundai Sept-08 IOM DFDE TZ Mk. III 4 Indonesia-US Tangguh 2033

British Trader 138,000 BP Shipping BP Shipping Samsung Dec-02 Isle of Man S TZ Mk. III 4 Engas

Broog 135,466 J4 Consortium NYK Line Mitsui Chiba May-98 Japan S Moss 5 Qatar-Japan Qatargas 2023

Bubuk 77,670 Brunei Shell Tkrs STASCO La Seyne Oct-75 Brunei S GT NO 82 5 Brunei-Japan Brunei LNG 2013

Bu Samra 266,000 QGTC Stasco Samsung Dec-08 Qatar DRL TZ Mk. III 5 Qatar-Atl’c Basin Qatargas 2033

BW Suez Paris 162,400 BW Gas BW Gas Daewoo May-09 N.I.S. DFDE GT NO 96 4 Yemen LNG Yemen-Atlantic

BW Suez Brussels 162,400 BW Gas BW Gas Daewoo May-09 N.I.S. DFDE GT NO 96 4 Yemen LNG Yemen-Atlantic

Cadiz Knutsen 138,826 Knutsen/ Knutsen/ IZAR Jun-04 Spain S GT NO 96 4 Egypt-Spain Engas 2030

Marpetrol Marpetrol Puerto Real

Castillo 173,600 Elcano Elcano STX Aug-10 Malta S GT NO. 96 Various

de Santisteban

Castillo de Villalba 138,000 Elcano Elcano IZAR Nov-03 Spain S GT NO 96 4 Algeria-Spain Sonatrach

Puerto Real

Catalunya Spirit 138,000 Teekay LNG Teekay LNG IZAR Sestao Mar-03 Liberia S GT NO 96 4 Trinidad - Spain Atlantic LNG 2024

Partners Partners

Celestine River 145,000 KLNG KLNG Kawasaki Dec-07 S Moss Various-US 2017

Cheikh El Mokrani 75,500 Med LNG Corp Hyproc/MOL June-07 Liberia S TZ Mk. III 4 Intra-Med Sonatrach 2032

Clean Energy 150,000 Pegasus Shiph’d Dynagas Hyundai Mar-07 Marshall Is. S TZ Mk. III 4 Available

Clean Force 150,000 Seacrown Mariti Dynagas Hyundai Jan-08 Marshall Is. S TZ Mk. III 4 Various

Clean Power 150,000 Lance Shipping Dynagas Hyundai Oct-07 Marshall Is. S TZ Mk. III 4 Available

Clearsky 171,800 Stena Stena Daewoo Sept-10 Panama DFDE GT NO 96 4 Various

Crystalsky 171,800 Stena Stena Daewoo Jul-10 Panama DFDE GT NO 96 4 Various

Cygnus Passage 145,400 Cygnus LNG NYK Line Mitsubishi Feb-09 Panama S Moss 4 Sakhalin-others

Dapeng Moon 147,000 China Ships China Ships Hudong Jul-09 China S GT NO 96 4 Aus-China Various

Dapeng Star 147,000 China Ships China Ships Hudong Nov-09 China S GT NO 96 4 Aus-China Various

Dapeng Sun 147,000 China Ships China Ships Hudong Jul-07 China S GT NO 96 4 Aus-China Woodside Energy 2033

Descartes 50,000 Messigaz Gazocean Atlantique France S TZ Mk. I 6 Algeria-France Sonatrach 2013

Dewa Maru 125,000 J3 Consortium K Line Mitsubishi Jul-84 Japan S Moss 5 Indonesia - Japan Pertamina

Nagasaki

Disha 136,000 Petronet LNG Ltd. SCI Daewoo Jan-04 Malta S GT NO 96 4 Qatar-India Qatargas 2029

Doha 137,350 J4 Consortium NYK Line Mitsubishi Jun-99 Japan S Moss 5 Qatar-Japan Qatargas 2024

Nagasaki

Duhail 210,100 ProNav ProNav Daewoo Jan-08 Germany DRL GT NO 96 4

Dukhan 135,000 J4 Consortium MOL Mitsui Chiba Oct-04 Japan S Moss 4 Qatar-Spain Qatargas 2024

Dwiputra 127,385 Humpuss Humolco Mitsubishi Mar-94 Bahamas S Moss 4 Indonesia - Japan Pertamina

Consortium Nagasaki

Ebisu 147,547 Golar LNG MOL Kawasaki Sep-08 Bahamas S Moss 4 World Wide NWSSSC Golar LNG

Echigo Maru 125,570 J3 Consortium NYK Line Mitsubishi Aug-83 Japan S Moss 5 Indonesia - Japan Pertamina

Nagasaki

Edouard L.D. 129,300 Dynagas Dynagas Dunkerque Dec-77 France S GT NO 85 5 Algeria - France Sonatrach 2013

Ejnan 145,000 4J NYK Samsung Jan-07 Luxemb’g S TZ Mk. III RasGas 2032

Ekaputra 136,400 Humpuss Humolco Mitsubishi Jan-90 Liberia S Moss 5 Indonesia -Taiwan Pertamina 2014

Consortium Nagasaki

Energy Advance 145,000 Tokyo LNG Tankers MOL Kawasaki Mar-05 Japan S Moss 4 Australia - Japan Darwin 2025

Sakaide

Energy Confidence 155,000 Tokyo LNG MOL Kawasaki Apr-09 Panama S Moss 4 Various-Japan

Energy 147,600 Tokyo LNG MOL Kawasaki Sep-03 Japan S Moss 4 Australia Darwin 2025

Frontier Tankers Sakaide

Energy 147,000 Tokyo LNG Tankers Kawasaki May-08 Japan S Moss 4 Australia/var -Japan 2025

Navigator MOL Sakaide

Energy Progress 145,000 MOL MOL Kawasaki NOV-06 Japan S Moss 4 Indonesia - Japan Bayu Undan LNG 2026

Excalibur 138,200 Exmar/ Excelerate Exmar Daewoo Oct-02 Luxemb'g S GT NO 96 4

Excel 138,106 Exmar/ MOL Exmar Daewoo Sep-03 Belgium S GT NO 96 4

Excelerate 138,000 Exmar/Excelerate Exmar Daewoo Oct-06 Belgium S GT NO 96 4 Various Various

Excellence 138,000 GKFF Ltd. Exmar Daewoo May-05 Luxemb'g S GT NO 96 4 Various Excelerate Energy 2025

Excelsior 138,000 Exmar Exmar Daewoo Jan-05 Luxemb'g S GT NO 96 4

p26-31:LNG 3 17/06/2011 09:46 Page 3

28 • LNG journal • The World’s Leading LNG publication

CARRIER FLEET

Exemplar 150,900 Exmar Exmar Daewoo Jun-10 Belgium S GT NO 96 4

Expedient 151,000 Exmar Exmar Daewoo Nov-09 Belgium S GT NO 96 4 Various

Explorer 150,900 Exmar/Excelerate Exmar Daewoo Mar-08 Belgium S GT NO 96 4 Excelerate Excelerate

Express 151,000 Exmar/Excelerate Exmar Daewoo May-09 Belgium S GT NO 96 4 Excelerate Energy Various

Exquisite 150,900 Exmar Exmar Daewoo Sep-09 Belgium S GT NO. 96 4 Various

Fraiha 210,100 J5 Consortium K Line/NYK Line Daewoo Sept-08 Marshall I DRL GT NO 96 4 Qatar-Atl’c Basin Qatargas 2033

Fuwairit 138,000 Peninsular LNG MOL Samsung Jan-04 Luxemb'g S TZ Mk. III 4 Qatar-Italy RasGas II 2029

Galea 134,425 Shell Shipping STASCO Mitsubishi Oct-02 Singapore S Moss 5 Shell

Nagasaki

Galeomma 126,540 Shell Shipping STASCO Newport News Dec-78 Singapore S TZ Mk. I 6 Oman-Spain Oman

Galicia Spirit 140,620 Teekay LNG Teekay LNG Daewoo Jul-04 Liberia S GT NO 96 4 Eqypt-Spain Engas 2034

Partners Partners

Gaselys 153,500 GdF/NYK NYK Line Atlantique Mar-07 France DFDE CS 1 4 Egypt-France Engas 2027

Gallina 134,425 Shell Shipping STASCO Mitsubishi Oct-02 Singapore S Moss 5 Shell

Nagasaki

Gaslog Savannah 155,000 GasLog Ltd Ceres LNG Samsung May-10 Bermuda DFDE GTT Mk. III 4

Gaslog Singapore 155,000 GasLog Ltd Ceres LNG Samsung July-10 Bermuda DFDE GTT Mk. III 4

Gaz de France 74,000 Gaz de France Gazocean Chantiers Dec-06 France DFDE CS1 4 Algeria-France Sonatrach 2013

Energy d’Atlantique

GDF-Suez Cape 145,000 Hoegh LNG/MOL Hoegh LNG/MOL Samsung May-10 Liberia DFDE TZ Mk. III 4 FSRU Atlantic Basin

Ann

GDF-Suez Neptune1450,000 Hoegh LNG/MOL Hoegh LNG/MOL Samsung Dec-09 Liberia DFDE TZ Mk. III 4 FSRU Atlantic Basin

GDF-Suez Point 154, 200 LNG Japan MOL Imabari/Koyo Feb-10 Panama DFDE TZ Mk. III 4 Various

Fortin

Gemmata 138,100 Shell Shipping STASCO Mitsubishi Mar-04 Singapore S Moss 5 Shell

Nagasaki

Ghasha 137,510 National Gas National Gas Mitsui Jun-95 Liberia S Moss 5 Abu Dhabi - Japan ADGAS 2021

Shipping Shipping

Gimi 126,277 Golar LNG Wilhelmsen Moss Dec-76 UK S Moss 6 Qatar - Spain Qatar BG

Stavanger

Golar Arctic 140,645 Golar LNG Wilhelmsen Daewoo Dec-03 MI S GT NO 96 4 World Wide Shell Spot

Golar Freeze 125,850 Golar LNG Golar LNG HDW Feb-77 UK S Moss 5 FSRU

Golar Grand 145,880 Golar LNG Wilhelmsen Daewoo 2006 IoM GT NO 96 4 World Wide charter

Golar Maria 145,950 Golar LNG Wilhelmsen Daewoo 2006 Marshall I GT NO 96 4 World Wide charter

Golar Mazo 135,225 Golar LNG/CPP Thome Mitsubishi Jan-00 Liberia S Moss 5 Indonesia-Taiwan Pertamina 2027

Golar Spirit 129,000 Golar LNG Thome Kawasaki Sakaide Sep-81 MI S Moss 5 Brazil FSRU Spot Petrobras 2018

Golar Viking 140,000 Golar LNG Wilhelmsen Hyundai Jan-05 MI S Moss 4 various

Golar Winter 138,250 Golar LNG Thome Daewoo Apr-04 MI S GT NO 96 4 Brazil FSRU Spot Petrobras 2019

Grace Acacia 150,000 Algaet Shipping NYK Line Hyundai Jan 07 Japan S TK MK III 4 Various

Grace Barleria 150,000 Swallowtail Ship NYK Line Hyundai Oct-07 Japan S TZ Mk. III 4 Available

Grace Cosmos 150,000 AGH Shipping NYK Line Hyundai Mar-08 Japan S TZ Mk. III 4 Various/cadet training

Gracilis 138,830 Golar LNG STASCO Hyundai Jan-05 MI S TZ Mk III 4 World Wide Shell BG 2011

Granatina 140,645 Shell Shipping STASCO Daewoo Dec-03 Singapore S GT NO 96 4 Shell

Grand Aniva 147,200 Sovcomflot/NYK NYK Line Mitsubishi Jan-08 Japan S Moss 4

Grand Elena 147,200 Sovcomflot/NYK NYK Line Mitsubishi Oct-07 Japan S Moss 4

Grand Mereya 147,200 Primorsk/MOL/K Line MOL Chiba May-08 Japan S Moss 4 Russia-Japan Sakhalin II

Hanjin Muscat 138,200 Hanjin Shipping Hanjin Line Hanjin Jul-99 Panama S GT NO 96 4 Oman-Korea Oman Gas 2019

Hanjin Pyeong Taek 130,600 Hanjin Shipping Hanjin Line Hanjin Sep-95 Panama S GT NO 96 4 Indonesia - Korea Pertamina 2016

Hanjin Ras Laffan 138,214 Hanjin Shipping Hanjin Line Hanjin Jul-00 Panama S GT NO 96 4 Qatar-Korea QatarGas 2020

Hanjin Sur 138,333 Hanjin Shipping Hanjin Line Hanjin Jan-00 Panama S GT NO 96 4 Oman-Korea Oman Gas 2020

Hilli 126,227 Golar LNG Wilhelmsen Moss Stavanger Dec-75 UK S Moss 6 World Wide Spot

Hispania Spirit 140,500 Teekay Teekay LNG Daewoo Sep-02 Spain S GT NO 96 4 Trinidad-U.S. Atlantic LNG 2033

LNG Partners Partners

Hoegh Gandria 125,820 Hoegh LNG Hoegh LNG HDW Oct-77 Norway S Moss 5 Indonesia -Korea Pertamina

Hyundai Aquapia 135,000 Hyundai MM Hyundai MM Hyundai Mar-00 Panama S Moss 4 Oman-Korea Oman Gas 2020

Hyundai 135,000 Hyundai MM Hyundai MM Hyundai Jan-00 Panama S Moss 4 Qatar-Korea RasGas 2020

Hyundai Ecopia 145,000 Hyundai Hyundai Hyundai Nov-08 Panama S TZ Mk. III 4 Various Various

Hyundai Greenpia 125,000 Hyundai MM Hyundai MM Hyundai Nov-96 Panama S Moss 4 Indonesia - Korea Pertamina 2017

Hyundai Oceanpia 135,000 Hyundai MM Hyundai MM Hyundai Jul-00 Panama S Moss 4 Oman-Korea Oman Gas 2020

Hyundai Technopia 135,000 Hyundai MM Hyundai MM Hyundai Jul-00 Panama S Moss 4 Qatar-Korea RasGas 2019

Hyundai Utopia 125,182 Hyundai MM Hyundai MM Hyundai Jun-94 Panama S Moss 4 Indonesia - Korea Pertamina 2015

Iberica Knutsen 138,000 Knutsen OAS Knutsen OAS Daewoo Aug-06 Norway S GT 96 4 Qatar-various Gas Natural

Ibra LNG 147,100 Oman Gas Samsung Jun-06 Panama S TK Mk. III 4 Oman-Japan Oman LNG

Ibri LNG 145,000 Oman Gas Mitsubishi Jul-06 Panama S TK Mk. III 4 Oman-Japan Oman LNG

Isabella 35,500 Chemikalien Chemikalien La Seyne Apr-75 Liberia S GT NO 82 5 Libya-Spain Sirte Oil

Seetransport Seetransport

Ish 137,540 National Gas National Gas Mitsubishi Nov-95 Liberia S Moss 5 Abu Dhabi - Japan ADGAS 2019

Shipping Shipping Nagasaki

K Acacia 138,017 Korea Line Korea Line Daewoo Jan-00 Panama S GT NO 96 4 Oman-Korea Oman Gas 2020

K Freesia 135,256 Korea Line Korea Line Daewoo Jun-00 Panama S GT NO 96 4 Qatar-Korea RasGas 2020

K Jasmine 145,700 Korea Line Korea Line Daewoo Mar-08 Panama S GT NO 96 4 Various-Korea Kogas offtake

K Mugungwha 152,000 K Line K Line Daewoo Nov-08 Panama S GT NO 96 4 Various Various

Kayoh Maru 1,517 Daiichi Tankers Daiichi Tankers Imamura Jan-88 Japan Cylinders 2 Japanese Domestic Trade

Khannur 126,360 Golar LNG Wilhelmsen Moss Stavanger Jul-77 UK S Moss 6 World Wide Atlantic BG 2011

Kotawaka Maru 125,200 J3 Consortium NYK Line Kawasaki Jan-84 Japan S Moss 5 Australia - Japan Darwin 2024

Sakaide

Lala Fatma 145,000 Algeria Nippon Hyproc/ MOL Kawasaki Dec-04 Japan S Moss 4 Exports from Algeria Sonatrach 2030

N'Soumer Gas Sakaide

Larbi Ben M'Hidi 129,750 SNTM-Hyproc SNTM- Hyproc La Seyne Jun-77 Algeria S GT NO 85 5 Algeria - Turkey Sonatrach 2014

Lijmilya 261,700 QGTC STASCO Daewoo Sept-08 Marshall I DRL GT NO. 96 5 Qatar-Atlantic Basin

LNG Abuja 126,530 Bonny Gas Anglo-Eastern GD Quincy Sep-80 Bahamas S Moss 5 Nigeria-Spain/ Nigeria LNG 2019

Transport Management France/Turkey

p26-31:LNG 3 17/06/2011 09:46 Page 4

LNG journal • June 2011 • 29

CARRIER FLEET

LNG Adamawa 141,000 Bonny Gas Anglo-Eastern Hyundai Jun-05 Bermuda S Moss 4 Nigeria-Europe

Transport Management

LNG Akwa Ibom 141,000 Bonny Gas STASCO Hyundai Nov-04 Bermuda S Moss 4 Nigeria-Europe 2024

Transport

LNG Aquarius 126,300 MOL/LNG Japan ProNav Ship GD Quincy Jun-77 Marshall I. S Moss 5

Management

LNG Aries 126,300 MOL/LNG Japan ProNav Ship GD Quincy Dec-77 Marshall I. S Moss 5

Management

LNG Bayelsa 137,500 Bonny Gas STASCO Hyundai Feb-03 Bermuda S Moss 4 Exports from Nigeria Nigeria LNG 2019

Transport

LNG Benue 145,700 BW Gas BW Gas Daewoo Mar-06 Bermuda S GT NO 96 4 Exports from Nigeria Nigeria LNG 2026

LNG Bonny 133,000 Bonny Gas STASCO Kockums Dec-81 Bermuda S GT NO 88 5 Nigeria-Spain/ Nigeria LNG 2019

Transport France/Turkey GdF/BOTAS

LNG Borno 149,600 NYK Line NYK Line Samsung Aug-07 Japan S TZ Mk. III 4 Nigeria-Various Nigeria LNG 2027

LNG Capricorn 126,300 MOL/LNG Japan ProNav Ship GD Quincy Jun-78 Marshall I. S Moss 5 Indonesia - Japan Pertamina

Management

LNG Cross 141,000 Bonny Gas Anglo-Eastern Hyundai Sep-05 Bermuda S Moss 4 Nigeria-Europe

River Transport Management

LNG Delta 126,540 Bonny Gas STASCO Newport May-78 Isle of Man S TZ Mk. I 6 Nigeria-Spain/ Nigeria LNG 2023

Transport News France/Turkey

LNG Dream 145,000 Osaka Gas NYK Line Kawasaki Sep-06 Japan S Moss 4 Australia-Japan Woodside Energy

LNG Edo 126,530 Bonny Gas Anglo-Eastern GD Quincy May-80 Bahamas S Moss 5 Nigeria-Spain/ Nigeria LNG 2019

Transport Management France/Turkey

LNG Elba 41,000 ENI ENI Italcantieri Jan-70 Italy S Esso 4 Algeria - France Sonatrach 2013

Genoa

LNG Enugu 145,000 BW Gas BW Gas Daewoo Oct-05 Burma S GT NO 96 4 Exports from Nigeria Nigeria LNG 2026

LNG Fimina 133,000 Bonny Gas STASCO Kockums Jan-84 Bermuda S GT NO 88 5 Nigeria-Spain/ Nigeria LNG 2019

Transport France/Turkey

LNG Flora 127,700 J3 Consortium NYK Line Kawasaki Mar-93 Japan S Moss 4 Indonesia - Japan Pertamina 2014

Sakaide

LNG Gemini 126,300 MOL/LNG Japan ProNav Ship GD Quincy Sep-78 Marshall S Moss 5 Indonesia - Japan Pertamina 2010

Management Islands

LNG Imo 148,300 BW Gas BW Gas Daewoo Jun-08 Bermuda S GT NO 96 4 Nigeria-Various Nigeria LNG

LNG Jamal 135,330 Osaka Gas/ NYK Line Mitsubishi Oct-00 Japan S Moss 5 Oman - Japan Oman Gas 2024

J3 Consortium Nagasaki

LNG Kano 148,471 BW Gas BW Gas Daewoo Jan-07 Bermuda S GT No. 96 4 Nigeria-Various NLNG 2027

LNG Lagos 122,000 Bonny Gas STASCO Atlantique Bermuda S GT NO 85 6 Nigeria-Spain/ Nigeria LNG 2019

Transport France/Turkey

LNG Leo 126,400 MOL/LNG Japan ProNav Ship GD Quincy Dec-78 Marshall S Moss 5 Indonesia - Japan Pertamina

Management Islands

LNG Lerici 65,000 ENI ENI Italcantieri Mar-98 Italy S GT NO 96 4 Algeria-Italy Sonatrach 2021

Sestri

LNG Libra 126,400 MOL/LNG Japan ProNav Ship GD Quincy Apr-79 Marshall S Moss 5 Indonesia - Japan

Management

LNG Lokoja 148,300 BW Gas BW Gas Daewoo Dec-06 Bermuda S GT No. 96 4 Atlantic Basin Nigeria LNG 2027

LNG Ogun NYK Line NYK Line Samsung Aug-07 Japan S TZ Mk. III 4 Nigeria-Various Nigeria LNG 2027

LNG Ondo 148,300 BW Gas BW Gas Daewoo Sep-07 Bermuda S GT NO 96 4 Nigeria-Various Nigeria LNG 2027

LNG Oyo 140,500 BW Gas BW Gas Daewoo Dec-05 Bermuda S GT NO 96 4 Exports from Nigeria Nigeria LNG 2026

LNG Palmaria 41,000 ENI ENI Italcantieri Jun-69 Italy S Esso 4 Algeria-Italy Sonatrach 2017

Genoa

LNG Pioneer 138,000 MOL MOL Daewoo Jul-05 Luxemb'g S GT NO 96 4 Exports from Egypt Idku

LNG Port Harcourt 122,000 Bonny Gas STASCO Atlantique Sep-77 Bermuda S GT NO 85 6 Nigeria-Spain/ Nigeria LNG 2019

France/Turkey

LNG Portovenere 65,000 ENI ENI Italcantieri Sestri Jun-96 Italy S GT NO 96 4 Algeria-Italy Sonatrach 2017

LNG River Niger 141,000 Bonny Gas Anglo-Eastern Hyundai May-06 Bermuda S Moss 4 Nigeria-Europe

Transport Management

LNG River 145,910 BW Gas BW Gas Daewoo Nov-04 Bermuda S GT NO 96 4 Exports from Nigeria LNG 2026

Orashi Nigeria

LNG Rivers 137,231 Bonny Gas STASCO Hyundai Jun-02 Bermuda S Moss 4 Nigeria-Spain Nigeria LNG 2019

Transport

LNG Sokoto 137,231 Bonny Gas STASCO Hyundai Aug-02 Bermuda S Moss 4 Nigeria-France Nigeria LNG 2019

Transport

LNG Taurus 126,300 MOL/LNG Japan ProNav Ship GD Quincy Aug-79 Marshall S Moss 5 Indonesia - Japan

Management Islands

LNG Vesta 127,547 Tokyo Gas MOL Mitsubishi Jun-94 Japan S Moss 4 Indonesia - Japan Pertamina 2014

Consortium Nagasaki

LNG Virgo 126,400 MOL/LNG Japan ProNav Ship GD Quincy Dec-79 Marshall S Moss 5 Indonesia - Japan Pertamina

Management Islands

Lusail 138,000 Peninsular LNG K Line Samsung May-05 Luxemb'g S TZ Mk. III 4 Qatar-Italy Qatar 2030

Madrid Spirit 138,000 Teekay LNG Teekay LNG IZAR Jan-05 Spain S GT NO 96 4 Egypt-Spain Engas 2035

Partners Partners Puerto Real

Maersk Arwa 165,000 AP Moller Maersk Gas Samsung Sept-08 Marshall I DFDE TZ Mk. III 4 Various Various

Maersk Magellan 165,500 Moller-Maersk Moller-Maersk Samsung Sept-08 Denmark DFDE TZ Mk. III 4 Various

Maersk Marib 165,000 AP Moller Maersk Gas Samsung May-08 DIS DFDE TZ Mk. III 4 Yemen/Atlantic Basin 2033

Maersk Meridian 165,500 A.P. Moller Maersk Gas Samsung Jan-10 DIS DFDE TZ Mk. III 4 various

Maersk Methane 165,000 AP Moller Maersk Gas Samsung Mar-08 Denmark DFDE TZ Mk. III 4 Various

Maersk Qatar 145,000 AP Moller Maersk Gas Samsung Apr-06 Denmark S TZ Mk. III 4 Qatar-Italy Qatar 2031

Maersk Ras 138,270 AP Moller Maersk Gas Samsung Mar-04 Denmark S TZ Mk. III 4 Qatar-Italy RasGas II 2029

Laffan

Maran Gas 145,000 Kristen Maran Gas Daewoo Jul-05 Bermuda S GT NO 96 4 Qatar-Europe Qatar 2030

Asclepius Navigation Maritime

Maran Gas 145,700 Maran Maran Daewoo Sep-07 Greece S GT NO 96 4 Qatar-Europe Rasgas II 2032

Coronis

Matthew 126,540 Suez LNG Shiping Hoegh LNG Newport News Jun-79 Bahamas S TZ Mk. I 6 Trinidad-U.S Atlantic LNG 2019

p26-31:LNG 3 17/06/2011 09:46 Page 5

30 • LNG journal • The World’s Leading LNG publication

CARRIER FLEET

Mekaines 266,000 Naklilat Stasco Samsung Mar-09 Liberia DRL GT NO 96 4 Qatargas III Qatar-Atlantic Basin

Mesaimeer 210,100 Naklilat Stasco Hyundai Mar-09 Liberia DRL GT NO 96 4 Qatargas III Qatar-Atlantic Basin

Methane Alison 145,000 BG BG Samsung Aug-07 Bermuda S TZ III 4 Eq.Guinea-US Eq.Guinea LNG 2027

Victoria

Methane Becki Anne 170 000 BG Ceres Samsung Sep-10 Bermuda TFDE TZ Mk. III 4 Various

Methane Heather 145,000 BG BG Samsung Jul-07 Bermuda S Tz Mk. III 4 Eq.Guinea-US Eq.Guinea LNG 2027

Sally

Methane Jane 145,000 BG Ceres Hellenic Samsung Jun-06 Bermuda S TZ Mk. III 4 Egypt-US Engas 2026

Elizabeth

Methane Julia 170,000 BG Ceres Samsung Dec-09 Bermuda TFDE TZ Mk. III 4 Various

Louise

Methane Kari Elin 138,200 BG BG Samsung Jun-04 Bermuda S TZ Mk. III 4

Methane 145,000 BG BG Samsung Feb-07 Bermuda S TZ Mk. III 4 Eq.Guinea Marathon Oil 2027

Lake Charles -Atlantic Basin

Methane 145,000 BG Ceres Hellenic Samsung Aug-06 Bermuda S TZ Mk. III 4 Various Engas 2026

Lydon Volney

Methane Mickie 170,000 BG Ceres Samsung Nov-10 Bermuda TFDE TZ Mk. III 4 Various

Harper

Methane Nile 145,000 BG BG Samsung Dec-07 Bermuda S TZ Mk. III 4 Egypt - Engas 2026

Eagle Atlantic Basin

Methane Patricia 170 000 BG Ceres Samsung Oct-10 Bermuda S TZ Mk. III 4 Various

Camila

Methane Princess 138,159 Golar LNG Wilhelmsen Daewoo 2003 UK S GT NO 96 4 World Wide Spot BG 2024

Methane Rita 145,000 BG/ Hellenic Ceres Samsung Mar-06 Bermuda S TZ Mk. III 4 Egypt-US Engas 2026

Andre

Methane Shirley 145,000 BG Eagle Gas Samsung Apr-07 Bermuda S TZ Mk. III 4 Equatorial Marathon Oil 2027

Elizabeth Guinea - US

Methania 131,230 Distrigas Exmar Boelwerf Oct-78 Belgium S GT NO 85 5 Algeria-Spain Sonatrach 2015

Min Lu 147,000 China Ships China Ships Hudong Aug-09 China S GT NO 96 4 Aus-China Various

Min Rong 147,000 China LNG Ships CSM Hudong Feb-09 S GT NO 96 4 NW Shelf /5 Australia-China

Mostefa Ben 125,260 SNTM-Hyproc SNTM-Hyproc La Ciotat Aug-76 Algeria S TZ Mk. I 6 Algeria-USA Sonatrach 2018

Boulaid

Mourad Didouche 126,130 SNTM-Hyproc SNTM-Hyproc Atlantique Jul-80 Algeria S GT NO 85 5 Algeria- Belgium Sonatrach

Mozah 266,000 QGTC STASCO Samsung Aug-08 Qatar DRL TZ Mk III 5 Qatar-Atl’c Basin Qatargas II

Mraweh 137,000 National Gas National Gas Kvaerner- Jun-96 Liberia S Moss 4 Abu Dhabi - Japan ADGAS 2021

Shipping Shipping Masa

Mubaraz 137,000 National Gas National Gas Kvaerner- Jan-96 Liberia S Moss 4 Abu Dhabi - Japan Livorno recei-

Shipping Shipping Masa ving facility

Muraq 210,100 J5-K Line NYK Daewoo May-08 Marshall I DRL GT NO 96 4 RasGas III Qatar-Atl’c Basin

Muscat LNG 149,170 Oman Gas/MOL MOL Kawasaki Mar-04 Japan S Moss 4 Oman - Spain Oman Gas

Sakaide

Neo Energy 149,700 Tsakos Tsakos Hyundai Feb-07 Liberia S GTT Mk II 4 Chile/Various

Nizwah LNG 145,000 Oryx LNG Carriers MOL Kawasaki Dec-05 Japan S Moss 4 Oman - Japan Oman Gas 2026

Sakaide

Norman Lady 87,600 Hoegh LNG Hoegh LNG Moss Jan-73 Norway S Moss 5 Trinidad - Spain Atlantic LNG 2020

Stavanger

North Pioneer 2,500 Japan Liquid Japan Liquid Kawasaki Dec-05 Japan D Cylinders 2 Japanese

Gas Gas Kobe Domestic Trade

Northwest 127,525 Australia LNG ALSOC Mitsubishi Jun-89 Australia S Moss 4 Australia - Japan NWS

Sanderling Nagasaki

Northwest 127,500 Australia LNG ALSOC Mitsui Feb-93 Australia S Moss 4 Australia - Japan NWS

Sandpiper Chiba

Northwest 127,450 Australia LNG STASCO Mitsubishi Nov-92 Bermuda S Moss 4 Australia - Japan NWS

Seaeagle Nagasaki

Northwest 127,500 Australia LNG BP Shipping Kawasaki Sep-91 Bermuda S Moss 4 Australia - Japan NWS

Shearwater Sakaide

Northwest 127,747 Australia LNG ALSOC Mitsui Sep-90 Australia S Moss 4 Australia - Japan NWS

Snipe Chiba

Northwest 127,600 Australia LNG ALSOC Mitsubishi Dec-94 Australia S Moss 4 Australia - Japan NWS

Stormpetrel Nagasaki

Northwest 127,708 J3 Consortium MOL Mitsui Chiba Nov-89 Japan S Moss 4 Australia - Japan NWS

Swallow

Northwest 138,000 Australia LNG Chevron Daewoo Mar-04 Australia S GT NO 96 4 Exports NWS 2024

Swan Transport from Australia

Northwest 127,590 J3 Consortium NYK Line Mitsubishi Sep-89 Japan S Moss 4 Australia - Japan NWS

Swift Nagasaki

Onaiza 210,100 Nakilat Stasco Daewoo Apr-09 Liberia DRL GT NO 96 4 Qatargas III Qatar-Atlantic Basin

Pacific Enlighten 145,000 LNG MT NYK Line Mitsubishi Mar-09 Japan S Moss 4 Various

Pacific Eurus 137,000 LNG Marine NYK Line Mitsubishi Mar-06 Bahamas S Moss 4 Australia - Japan Darwin 2024

Transport Nagasaki

Pacific Notus 137,006 Pacific LNG NYK Line Mitsubishi Sep-03 Bahamas S Moss 5 Australia - Japan Darwin 2024

Shipping Nagasaki

Pioneer Knutsen 1,100 Knutsen OAS Knutsen OAS Bijlsma Dec-03 Norway D Cylinder 2 Coastal Norway Naturgass Vest 2019

Polar Eagle 89,880 Polar LNG Marathon IHI Chita Jun-93 Liberia S IHI SPB 4 Alaska-Japan ConocoPhillips 2014

/Marathon

Provalys 153,500 Gaz de France Gazocean Chantiers Nov-06 France DFDE CS1 4 Egypt-France ELNG 2026

Puteri Delima 130,400 MISC MISC Atlantique Jan-95 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2015

Puteri Delima Satu 137,100 MISC MISC Mitsui Chiba Apr-02 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2023

Puteri Firuz 130,400 MISC MISC Atlantique May-97 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2018

Puteri Firuz 137,100 MISC MISC Mitsubishi Sep-04 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2024

Satu Nagasaki

Puteri Intan 130,400 MISC MISC Atlantique Aug-94 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2015

Puteri Intan Satu 137,100 MISC MISC Mitsubishi Dec-01 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2023

Nagasaki

p26-31:LNG 3 17/06/2011 09:46 Page 6

LNG journal • June 2011 • 31

CARRIER FLEET

Notes: Any observations, additions or suggested revisions to the LNG journal World LNG Carrier Fleet list should be sent to editor@lngjournal.com

Puteri Mutiera Satu 137,100 MISC MISC Mitsui Chiba Apr-05 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2025

Puteri Nilam 130,400 MISC MISC Atlantique Jun-95 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2016

Puteri Nilam Satu 137,100 MISC MISC Mitsubishi Sep-03 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2023

Nagasaki

Puteri Zamrud 130,400 MISC MISC Atlantique May-96 Malaysia S GT NO 96 4 Malaysia - Japan Petronas 2017

Puteri Zamrud Satu 137,100 MISC MISC Mitsui Chiba Apr-87 Malaysia S GT NO 96 4 Malaysia - Japan Atlantic LNG 2020

Raahi 136,000 Petronet LNG Ltd SCI Daewoo Dec-04 Malta S GT NO 96 4 Qatar-India Qatargas 2030

OSK Line

Ramdane Abane 126,130 SNTM-Hyproc SNTM-Hyproc Atlantique Jul-81 Algeria S GT NO 85 5 Algeria - France Sonatrach 2013

Rasheeda 266,000 QGTC STASCO Samsung Jun-10 Liberia DRL TZ Mk. III 5 Qatar-Atlantic Qatargas

Ribera del Duero 173,400 Knutsen Knutsen Daewoo Nov-10 Nor-NIS DFDE GT NO. 96 4 Various

Knutsen

Salalah LNG 147,000 Oman Gas/MOL MOL Samsung Dec-05 Japan S TZ Mk. III 4 Oman-Spain Oman 2026

SFC Arctic 71,500 Sovcomflot Unicom Kockums Jan-69 Liberia S GT NO 82 6 Trinidad-Spain Atlantic LNG 2012

SCF Polar 71,500 Sovcomflot Unicom Kockums Aug-69 Liberia S GT NO 82 6 Algeria-France Sonatrach 2012

Senshu Maru 125,000 J3 Consortium NYK Line Mitsui Chiba Feb-84 Japan S Moss 5 Indonesia - Japan Petamina 2011

Seri Alam 138,000 MISC MISC Samsung Oct-05 Malaysia S TZ Mk. III 4 Yemen-U.S. Yemen LNG 2028

Seri Amanah 145,000 MISC MISC Samsung Mar-06 Malaysia S TZ Mk. III 4 Yemen-U.S. Yemen LNG 2028

Seri Anggun 145,000 MISC MISC Samsung Nov-06 Malaysia S TZ Mk. III 4 Yemen-US Yemen LNG 2031

Seri Angkasa 145,000 MISC MISC Samsung Feb-07 Malaysia S TZ Mk. III 4 Petronas Various Malaysia-Pacific

Seri Ayu 145,000 MISC MISC Samsung Oct-07 Malaysia S TZ Mk. III 4 Various

Seri Bakti 152,300 MISC MISC Mitsubishi Mar-07 Malaysia S GT NO 96 4 Petronas Various Malaysia-Pacific

Seri Balhaf 152,000 MISC MISC Mitsubishi Sept-08 Malaysia S GT NO 96 4 Various Various

Seri Balquis 152,000 MISC MISC Mitsubishi Dec-08 Malaysia S GT NO 96 4 Various Various

Seri Begawan 152,300 MISC MISC Mitsubishi Dec-07 Malaysia S GT NO 96 4

Seri Bijaksana 152,300 MISC MISC Mitsubishi Feb-08 Malaysia S GT NO 96 4 Malaysia/var Petronas

Sevilla Knutsen 173,400 Knutsen Knutsen Daewoo June-10 N.I.S. DFDE GT NO 96 4

Shahamah 135,500 National Gas National Gas Kawasaki Oct-94 Liberia S Moss 5 Abu Dhabi - Japan ADGAS 2020

Shipping Shipping Sakaide

Shangra 266,000 QGTC STASCO Samsung Nov-09 Liberia DRL TZ Mk. III 5 Qatargas IV Qatar-Atlantic

Shinjyu Maru No.1 2,540 Shinwa Chemical CoShinwa Marine Imabari Higaki Aug-03 Japan D Cylinders 2 Japanese Domestic Trade

Simaisma 147,700 Maran Gas Maran Gas Daewoo Jul-06 Greece S GT No 96 4 Qatar-Europe Qatar 2030

Maritime Maritime

SK Splendor 138,375 SK Shipping SK Shipping Samsung Mar-00 Panama S TZ Mk. III 4 Oman-Korea Oman Gas 2020

SK Stellar 138,375 SK Shipping SK Shipping Samsung Dec-00 Panama S TZ Mk. III 4 Qatar-Korea RasGas 2020

SK Summit 138,000 SK Shipping SK Shipping Daewoo Aug-99 Panama S GT NO 96 4 Qatar-Korea RasGas 2019

SK Sunrise 138,306 I. S. Carriers SK Shipping Samsung Sep-03 Panama S TZ Mk. III 4 Qatar-Korea RasGas 2025

SK Supreme 138,200 SK Shipping SK Shipping Samsung Jan-00 Panama S TZ Mk. III 4 Qatar-Korea RasGas 2020

Sohar LNG 137,250 Oman Gas/ MOL MOL Mitsubishi Oct-01 Malta S Moss 5 Oman-France Oman Gas 2022

Nagasaki

STX Frontier 153,000 STX STX Hanjin Korea Dec-09 Panama DFDE TZ Mk. III 4 Various

Suez Point Fortin 154,200 Trinity LNG MOL Koyo Japan Nov-09 Panama S TZ Mk. III 4 Yemen LNG Yemen-Atlantic

Surya Aki 19,475 MCGC Int’l Homolco Kawasaki Feb-96 Bahamas S Moss 3 Ind’sia-Japan Pertamina 2020

Sakaide

Surya Satsuma 23,096 MCGC Int’l Humolco NKK Tsu Oct-00 Japan S TZ Mk. III 3 Indonesia - Japan Pertamina 2020

Taitar No. 1 145,000 NYK Line NYK Line Mitsubishi Oct-09 Liberia S Moss 4 Various

Taitar No. 3 145,000 NYK Line NYK Line Mitsubishi Jan-10 Liberia S Moss 4 Various

Taitar No. 4 145,000 NYK NYK Mitsubishi Jan-10 Liberia S Moss 4 Various

Tangguh Batur 145,700 Sovcomflot/NYK NYK Daewoo Dec-08 Cyprus S GT NO 96 Indonesia - China Tangguh 2033

Tangguh Foja 155,000 K Line K Line Samsung Jul-08 Panama DFDE TZ Mk. III 4 Indonesia - China Tangguh LNG

Tangguh Hiri 155,000 Teekay LNG Teekay LNG Hyundai Nov-08 IOM DFDE TZ Mk. III 4 I Indonesia - Atl’c Basin Tangguh 2033

Tangguh Jaya 145,700 K Line K Line Samsung Nov-08 Panama DFDE TZ Mk. III 4 Indonesia - China Tangguh 2033

Tangguh Palung 155,000 K Line K Line Samsung Mar-09 Panama DFDE TZ Mk. III 4 Indonesia -China Tangguh

Tangguh Sago 155,000 Teekay LNG Teekay LNG Hyundai Mar-09 IOM DFDE TZ Mk. III 4 Indonesia -Atlantic Tangguh LNG

Tangguh Towuti 145,700 Sovcomflot/NYK NYK Line Daewoo Oct-08 Cyprus S GT NO 96 4 Indonesia - China Tangguh 2033

Tellier 40,000 Messigaz Gazocean La Ciotat Jan-74 France S TZ Mk. I 5 Algeria - France Sonatrach 2013

Tembek 216,200 OSG/Nakilat Overseas Hdg Samsung Sep-07 Marshall Is DRL TZ Mk. III 4 Qatar-UK/Var. Qatargas II 2032

Tenaga Dua 130,000 MISC MISC Dunkerque Aug-81 Malaysia S GT NO 88 5 Malaysia - Japan Petronas 2205

Tenaga Empat 130,000 MISC MISC La Seyne Mar-81 Malaysia S GT NO 88 5 Malaysia - Japan Petronas

Tenaga Lima 130,000 MISC MISC La Seyne Aug-81 Malaysia S GT NO 88 5 Malaysia - Japan Pertamina 2010

Tenaga Satu 130,000 MISC MISC Dunkerque Sep-82 Malaysia S GT NO 88 5 Malaysia - Japan Petronas

Tenaga Tiga 130,000 MISC MISC Dunkerque Dec-81 Malaysia S GT NO 88 5 Malaysia - Japan Petronas

Trinity Arrow 154,900 K Line K Line Imabari Mar-08 S TZ Mk. III 4 Various/US Various

Shipbuilding

Umm Al Amad 210,100 J5 K Line/NYK Daewoo Aug-08 Marshall Is DRL GT NO 96 4 Qatar-Atlantic Basin Ras Gas III

Umm Al Ashtan 137,000 National Gas National Gas Kvaerner- May-97 Liberia S Moss 4 Abu Dhabi - Japan ADGAS 2021

Shipping Shipping Masa

Umm Bab 145,000 Kristen Navigation Maran Gas Daewoo Nov-05 Bermuda S GT NO 96 4 Qatar-Europe Qatargas 2030

Maritime

Umm Slaal 266,000 QGTC Stasco Samsung Nov-08 Qatar DRL TZ Mk. III 5 Qatar-Atlantic Basin Qatargas 2033

Valencia Knutsen 173 400 Knutsen Knutsen Daewoo Sept-10 Nor-NIS DFDE GT NO. 96 4 Various

Wakaba Maru 125,000 J3 Consortium K Line Mitsui Chiba Apr-85 Japan S Moss 5 Indonesia - Japan Pertamina

Woodside 165,500 A P Moeller Maersk Gas Samsung Dec-09 Singapore DFDE TZ Mk. III 4

Donaldson

YK Sovereign 127,125 SK Shipping SK Shipping Hyundai Dec-94 Panama S Moss 4 Indonesia - Korea Pertamina 2015

Zarga 266,000 QGTC STASCO Samsung Dec-09 Liberia DRL TZ Mk. III 5 Qatargas IV Qatar-Atlantic

Zekreet 135,420 J4 Consortium K Line Mitsui Chiba Dec-98 Japan S Moss 5 Qatar-Japan Qatargas 2024

p26-31:LNG 3 17/06/2011 09:46 Page 7

32 • LNG journal • The World’s Leading LNG publication

TABLES

Explanatory Notes� The tables do not include

the following types of LNG facilities :� Small marine satellite

terminals receiving LNG from liquefaction plants in their own country (such as exist in Norway) or which receive LNG transhipped from nearby reception terminals in their own country (such as in Japan)

� Satellite LNG storage facilities that receive LNG transported only by road or rail

� Expansions of LNG reception terminals are only shown if they involve new storage tanks

� Where there is a blank in the table the information is uncertain or unknown.

Any comments on the tables, and corrections/additionalinformation from terminalshareholders and projectdevelopers would be mostwelcome, and should be sent toJohn McKay e-maileditor@lngjournal.com

LNG Import TerminalsStorage

Country Location (Project) Owners Start up Tanks CapacityBelgium Zeebrugge Fluxys 1987 4 380,000

Canada Canaport Saint John Irving Oil, Repsol 2009 2 320,000

Chile Quintero ENAP, BG 2009 2 320,000

Mejillones LNG (FSRU) GDF-Suez Codelco 2010 1 160,000

China Fujian LNG (Xiuyu) CNOOC, Fujian I&D Corp. 2008 2 320,000

Guangdong CNOOC,BP 2006 2 320,000

Rudong PetroChina 2011 2 320,000

Shanghai CNOOC, Shenergy Group 2009 2 320,000

Dominican

Republic Andres AES 2003 1 160,000

France Fos Tonkin Elengy 1972 3 150,000

Montoir-de-Bretagne Elengy 1980 3 360,000

Fos Cavaou Gaz de France, Total 2010 3 330,000

Greece Revithoussa DEPA 2000 2 130,000

India Dabhol GAIL, NTPC (Ratnagiri Gas & Power) 2009 3 480,000

Dahej Petronet LNG 2004 4 640,000

Hazira Shell India 2005 2 320,000

Italy Panigaglia Snam 1969 2 100,000

Porto Levante (offshore GBS) ExxonMobil, Qatar Petroleum, Edison Gas 2009 2 250,000

Japan Negishi Tokyo Gas 1969 14 1,180,000

Sodegaura Tokyo Gas 1973 35 2,660,000

Ohgishima Tokyo Gas 1998 3 600,000

Higashi-Ohgishima Tokyo Electric 1984 9 540,000

Futtsu Tokyo Electric 1985 10 1,110,000

Yokkaichi LNG Chubu Electric 1988 4 320,000

Kawagoe Chubu Electric 1997 4 480,000

Yokkaichi Works Toho Gas 1991 2 160,000

Chita LNG Joint Toho Gas, Chubu Electric 1978 4 300,000

Chita LNG Toho Gas, Chubu Electric 1983 7 640,000

Chita - Midorihama Toho Gas 2001 1 200,000

Senboku I Osaka Gas 1972 4 180,000

Senboku II Osaka Gas 1977 18 1,585,000

Himeji Osaka Gas 1984 8 740,000

Himeji LNG Kansai Electric 1979 7 520,000

Yanai Chugoku Electric 1990 6 480,000

Niigata Nihonkai LNG, Tohoku Electric 1984 8 720,000

Oita Oita Gas, Kyushu Electric 1990 5 460,000

Tobata Kitakyushu LNG 1977 8 480,000

Fukuoka Saibu Gas 1993 2 70,000

Sodeshi Shizuoka Gas 1996 2 177,000

Hatsukaichi Hiroshima Gas 1996 2 170,000

Kagoshima Nippon Gas 1996 2 136,000

Shin-Minato Sendai City Gas 1997 1 80,000

Nagasaki Saibu Gas 2003 1 36,000

Sakai Kansai Electric, Cosmo OIl 2006 3 420,000

Mizushima Nippon Oil,Chugoku Electric 2006 1 160,000

Sakaide Shikoku Electric, Cosmo Oil 2011 1 180,000

Korea Pyeong-Taek Korea Gas Corp. (Kogas) 1986 12 1,280,000

Kwangyang POSCO 2005 3 365,000

Incheon Kogas 1996 18 2,480,000

Tong-Yeong Kogas 2002 10 1,400,000

Mexico Altamira Shell, Total, Mitsui 2006 2 300,000

Energia Costa Azul Sempra LNG 2008 2 320,000

Portugal Sines Transgas Atlantico 2003 2 240,000

Puerto Rico Penuelas EcoElectrica 2000 1 160,000

Spain Barcelona Enagas 1969 6 540,000

Huelva Enagas 1988 4 460,000

Cartagena Enagas 1989 4 437,000

Bilbao BP, Iberdola, Repsol, EVE 2003 2 300,000

Sagunto Union Fenosa, Endesa,Iberdola, Oman Oil 2006 2 300,000

Reganosa, Ferrol Union Fenosa, Endesa,Sonatrach,Tojeiro 2006 2 300,000

Taiwan Yung-An CPC 1990 6 690,000

Tai-chung CPC 2009 3 480,000

Thailand Map Ta Phut PTT LNG 2011 2 320,00

Turkey Marmara Ereglisi Botas 1994 3 255,000

Izmir EgeGaz 2006 2 280,000

USA Everett Suez LNG NA 1971 2 155,000

Lake Charles Southern Union 1982 4 425,000

Elba Island Southern LNG 2001 4 351,000

Cove Point Dominion 2003 6 530,000

Sabine Pass Cheniere 2008 5 800,000

Freeport Freeport LNG, ConocoPhillips, 2008 2 320,000

Zachry, Hastings

Cameron Sempra LNG 2009 3 480,000

Golden Pass, TX ExxonMobil 2010 5 775,000

UK Isle of Grain National Grid 2005 7 960,000

South Hook ExxonMobil, Qatar Petroleum,Total 2009 5 775,000

Dragon LNG, Milford Haven BG, Petronas, 4Gas 2009 2 310,000

p32-36:LNG 3 17/06/2011 09:48 Page 2

LNG journal • June 2011 • 33

TABLES

China Darlian PetroChina 2012 2 320,000

Guangxi PetroChina 2012 1 160,000

Haikou, Hainan CNOOC, Hainan Govt. 2014 1 160,000

Ningbo, Zheijang CNOOC, Zhejiang Energy 2012 1 160,000

Qingdao, Shangdong Sinopec 2011 1 160,000

Swatuo, Guangdong CNOOC 2014 2 320,000

Tangshan, Hebei PetroChina, Beijing Enterprises 2012 2 320,000

Yingkou, Liaoning CNOOC 2012 2 320,000

Zhuhai, Guangdong CNOOC 2012 2 320,000

Croatia Adria LNG E.ON-Ruhrgas, OMV, Total, INA, Geoplin 2011

France Fos Faster Marseilles Vopak, Royal Dutch Shell 2015

Le Havre (Antifer) Gaz de Normandie 2014 3 510,000

Dunkirk LNG EDF 2014 1-3

Germany Willemshaven DFTG (E.ON Ruhrgas, VNG) 2011 2 320,000

India Kochi, Kerala Petronet LNG 2011 220,000

Ennore Indian Oil Corp 2015 2 320,000

Mundra Gujarat State Petroleum, Adani Group 2014 2 320,000

Indonesia Cilegon, West Java PLN, Pertamina 2012

Brindisi BG 2011+ 2 320,000

Italy Rosignano (Livorno, offshore) BP, Edison, Solvay 2011 1 160,000

Taranto Gas Natural 2011+ 2 300,000

Monfalcone (offshore) Endesa 2011+

Trieste Gas Natural 2011+ 2 280,000

Porto Empocole Sicily Enel 2013

Triton LNG FSRU Hoegh LNG/GDF-Suez 2012

Livorno (FSRU) E.ON, Golar, OLT Energy 2011 137,000

Japan Joetsu Teikoku Oil (Inpex) 2014 2 360,000

Okinawa Okinawa Electric Power 2012

Shikoku/Sakaide LNG Shikoku Electric Power, Cosmo Oil Co., 2011

Hachinohe LNG Nippon Oil 2015 2 280,000

Kenya Mombasa Government studies

Korea Incheon (expansion) Kogas 2015 11

Pyeong-Taek (expansion) Kogas 2015 10

Lithuania Baltic Klaipedos Nafta 2014 2 320,000

Malaysia Malacca FSRU Petronas 2012 1 138,000

Mexico Manzanillo CFE 2011 2 300,000

Puerto Libertad, Sonora DKRW Energy, Sonora Govt. 2011 2 320,000

Netherlands Rotterdam Gate LNG, Gasunie, Royal Vopak 2011 2 360,000

Pakistan Karachi Sui Southern Gas Company Ltd. 2012+

Philippines Mariveles, Bataan GNPower 2012 2 280,000

Calaga LNG, Manila Bay Batangas Govt. 2015

Poland Swinoujscie, Baltic Gaz System 2013 2 320,000

Portugal Madeira Empresa de Electricidade da Madeira 2013+

Singapore Singapore Singapore Energy Authority 2013 3 540,000

Spain El Musel, Gijón, Enagas 2012 2 300,000

Spain - Arinaga, Gran Canaria Gascan, Unelco Endesa 2011 1 150,000

Canary Is. Granadilla, Tenerife Gascan, Unelco Endesa 2011 1 150,000

Ukraine Black Sea coast Naftogaz

USA Corpus Christi, TX Cheniere Energy 2012+ 3 480,000

Creole Trail, LA Cheniere Energy 2012+ 4 640,000

HiLoad, Gulf (offshore FSRU) TORP Technology, Golar LNG 2012+

Ingleside Energy, TX Occidental Oil & Gas Corp 2012+ 2 320,000

Jordan Cove, OR Fort Chicago LNG/Energy Projects 2013+ 2 320,000

Maine LNG Town of Calais Gelber Corp. 2012+ 2 320,000

Oregon LNG (Warrenton) Oregon LNG 2013 3 480,000

Pascagoula, MS Gulf LNG Energy 2012 2 320,000

Port Arthur, TX Sempra Energy 2013+ 3 480,000

Port Dolphin Florida (offshore) Hoegh LNG 2013

Vista Del Sol, Ingleside, TX ExxonMobil 2012+ 3 465,000

Country Location/Project Owners/Project Developers Start up Storage

Tanks Capacity

LNG Import Terminal Projects

p32-36:LNG 3 17/06/2011 09:48 Page 3

34 • LNG journal • The World’s Leading LNG publication

TABLES

LNG Seasonal Import FacilitiesCountry Location (Project) Owners Start up

Argentina Bahia Blanca GasPort Excelerate/YPF Repsol 2008

Escobar GasPort Excdelerate/Enarsa 2011

Brazil Pecem, Guanabara (FSRU) Petrobras 2009

Dubai Jebel Ali Port DSA of UAE 2010

Kuwait Mina Al-Ahmadi KPC/Excelerate 2009

UK Teesside GasPort Excelerate 2007

USA Northeast Gateway Excelerate 2008

Neptune LNG Offshore Massachusetts Hoegh LNG/GDF-Suez 2010

New LNG Export ProjectsCountry Location/Project Project Developers Planned Number of Capacity

Start Up Trains In MPTA

Australia Gladstone LNG Santos, Petronas, 2015 1 3.5

Total, Kogas

Curtis LNG BG Group 2014 2 7.5

Australia Pacific LNG ConocoPhillips 2014 2 7.5

Origin Energy

Fisherman’s Landing Shell, PetroChina 2014 2 8.0

Country Location/Project Developers Planned start up No of Trains Capacity MTPA

ALGERIA Arzew (Gassi Touil) Sonatrach 2012 1 4.7

Skikda Sonatrach 2011 1 4.5

ANGOLA Soyo Sonangol, Chevron, BP, ENI, Total 2012 1 5.2

AUSTRALIA Bonaparte FLNG GDF-Suez/Santos 2016 1 2.0

Browse LNG Woodside 2016 2 10.0

Gorgon LNG Chevron, Shell, ExxonMobil 2015 4 20.0

Ichthys LNG INPEX, Total 2016 2 6.0

Pilbara LNG BHPBilliton, ExxonMobil 2015 2 6.0

Pluto LNG Woodside, Tokyo Gas, Kansei 2011 1 4.8

Prelude FLNG Shell 2016 1 3.5

Sunrise LNG Woodside, Osaka Gas, ConocoPhillips, Shell 2015 1 7.0

Tassie Shoal MEO Australia Ltd 2013 1 3.0

Wheatstone LNG Chevron 2014 1 5.0

CANADA Kitimat LNG Apache, Galveston 2014 1 5.0

B.C. LNG LNG Partners (Houston) 2015 1 0.7

BC LNG Douglas Channel LNG Partners 2016 1 1.0

INDONESIA Abadi FLNG Inpex 2016 1 4.5

Sulawesi LNG Medco Energi, Pertamina, Mitsubishi 2014 1 2.0

Sengkang LNG World Energy Corp. 2012 4 2.0

NIGERIA NLNG Train 7 NNPC, Shell, BP, Total 2016+ 1 8.4

Brass LNG NNPC, ENI, ConocoPhillips, Total 2016+ 2 10.0

Flex LNG (offshore) Flex LNG, Peak Petroleum 2012 1 1.0

Olokola LNG NNPC, Chevron, Shell, BG 2016+ 4 20.0

PAPUA NEW GUINEA Gas Niugini InterOil, Petromin, Pacific LNG 2015 2 8.0

PNG LNG ExxonMobil, Oil Search, Santos, Nippon Oil 2015 2 6.6

RUSSIA Shtokman LNG Murmansk Gazprom, Statoil, Total 2017 2 15.0

Yamal LNG Siberia Novatek, Gazprom, Total 2016 3 16.5

USA Cove Point LNG, Maryland Dominion, Statoil 2016 studies

Freeport LNG, Texas Freeport LNG 2016 2 8.0

Lake Charles, Louisiana BG, Southern Union 2016 3 15.0

Sabine Pass LNG, Louisiana Cheniere Energy 2015 2 7.0

CSG-to-LNG Export Projects

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ABU DHABI Das Island (Adgas) ADNOC, Mitsui, BP, Total 1977 2 3.2 3 240,000

(UAE) 1994 1 2.5

ALGERIA Arzew Sonatrach GL4Z 1964 3 1.1 4 71,000

Arzew Sonatrach GL1Z 1978 6 7.8 3 300,000

Arzew Sonatrach GL2Z 1980 6 8.0 3 300,000

Skikda Sonatrach GL1K II 1980 3 3.0 2 112,000

AUSTRALIA Karratha NWS Woodside, Shell, BHP 1989 2 5.0 4 260,000

(BP, Chevron 1992 2.5 1 130,000

(Mistubishi/Mitsui) 2004 1 4.4 1 130,000

NWS partners 2008 1 4.4 1 130,000

Darwin Darwin (Bayu Undan) ConocoPhillips, 2006 1 3.5 1 188,000

Santos, Eni, Inpex, TEPCO, Tokyo Gas

BRUNEI Lumut Brunei/Shell/Mitsubishi/Total 1972-74 5 7.2 3 176,000

EGYPT Damietta Union Fenosa, EGPC, EGAS 2004 1 5.0 2 300,000

Idku (Egypt LNG) EGPC, EGAS, BG, GdF, Petronas 2005 2 7.2 2 280,000

EQ.GUINEA Bioko Island Marathon, Sonagas, 2007 1 3.4 2 272,000

Mitsui, Marubeni

INDONESIA Arun I Pertamina, ExxonMobil, JILCO 1978 1 1.5 5 507,000

Arun II 1984 2 3.0

Arun III 1986 1 2.0

Bontang I Pertamina, VICO, JILCO, Total 1977 2 5.2 5 635,000

Bontang II 1983 2 5.2

Bontang III 1989 1 2.8

Bontang IV 1993 1 2.8

Bontang V 1997 1 2.8

Bontang VI 1999 1 3.0

Tangguh BP, MI Berau, CNOOC, Nippon, LNG Japan 2008 2 7.6 2 340,000

LIBYA Marsa el Brega Sirte Oil (NOC/Shell upgrading) 1970 2 (2.5) 2 96,000

MALAYSIA Bintulu (MLNG Satu) Petronas, Sarawak, Mitsubishi 1983 3 8.1 4 260,000

Bintulu (MLNG Dua) Petronas, Shell, Sarawak, Mitsubishi 1995 3 7.8 1 65,000

Bintulu (MLNG Tiga) Petronas, Shell, Sarawak, Mitsubishi, Nippon Oil 2003 2 6.8 1 120,000

NIGERIA Bonny Island NNPC, Shell, Total, Eni 1999 2 6.4 2 168,400

Nigeria LNG (formed by above) 2002 1 3.2 1 84,200

Nigeria LNG 2006 2 8.2

Nigeria LNG 2008 1 4.1 1 84,200

NORWAY Melkoya Island StatoilHydro, Total, GDF-Suez, Petoro, Hess 2007 1 4.2 2 280,000

OMAN Oman LNG Oman Govt., Shell, Total, Korea LNG 2000 2 6.6 2 240,000

Mitsubishi , Mitsui, Partex and Itochu

Qalhat LNG Oman Govt.,Oman LNG Union Fenosa, Osaka Gas, & Itochu 2006 1 3.7 2 240,000

PERU Peru LNG Hunt Oil, Repsol, Marubeni, SK Group 2010 1 4.4 2 260,000

QATAR Ras Laffan (Qatargas) Qatar Petroleum, ExxonMobi, Total, Marubeni, Mitsui 1997 3 9.7 4 340,000

(RasGas) QP, ExxonMobil, Kogas, Itochu & LNG Japan 1999 2 6.6 3 420,000

(RasGas II) QP, ExxonMobil 2004 1 4.7 2 180,000

(Ras Gas II) QP, ExxonMobil 2005 1 4.7

(RasGas II) QP, ExxonMobil 2007 1 4.7

(RasGas III) T6 QP, ExxonMobil 2009 1 7.8

(RasGas III) T7 QP, ExxonMobil 2009 1 7.8

(QatarGas II) T1 QP, ExxonMobil 2008 1 7.8 2 145,000

(QatarGas II) T2 QP, ExxonMobil, Total 2009 1 7.8 2 145,000

(QatarGas III) T1 QP, ConocoPhillips, Mitsui 2010 1 7.8 2 145,000

(QatarGas IV) T1 QP, Shell 2010 1 7.8 2 145,000

RUSSIA Sakhalin Island (Sakhalin Energy) Gazprom, Shell, Mitsui, Mitsubishi 2009 2 9.6 2 200,000

TRINIDAD Point Fortin Train 1 BP, BG, Repsol, Suez, NGC 1999 1 3.0 2 204,000

& TOB AGO Train 2 BP, BG Repsol 2002 1 3.3 1 160,000

Train 3 BP, BG, Repsol 2003 1 3.3 1 160,000

Train 4 BP, BG Repsol, NGC 2005 1 5.2 1 160,000

USA Kenai - Alaska ConocoPhilips, Marathon Oil 1969 2 1.3 3 108,000

YEMEN Bal-Haf Yemen LNG, Total, Yemen Gas, Hunt Oil, SK Group, Hyundai 2009 2 6.7 2 320,000

LNG ExportersCountry Location/Project Shareholders Start up Liquefacton Storage

Trains capacity No. of Total(nominal) mtpa tanks capacity m3

LNG journal • June 2011 • 35

TABLES

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LNG OneWorld.com

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