In this issue:1 Australia increases

output and expands LNG perspectives

LNG Journal Editor, John McKay

6 Commercial engineering of LNG value chain merits more attention

Neil Wragg and David Haynes, Advantica Group

12 LNG project relationships change as NOCs gain more contract leverage

Nick Prowse, Norton Rose LLP

16 A round-up of latestevents, companyand industry news

News Index

25 Offshore LNG develops too for new regasification technology

Hans Kristian Danielsen and Goran Andreassen

28 BP develops studied approach to liquefaction in an Arctic climate

Martin Josten andJohn Kennedy

31 World Carrier Fleet:More new-builds commissioned

38 Tables of liquefaction plants and LNG import terminals worldwide

June 2008

44 pagesessential LNG

news!

Australia increases output andexpands LNG perspectivesAustralia’s LNG exports have graduallyexpanded since the first shipments fromthe North West Shelf in 1989. Thecountry is now on track, along withNigeria, to be the world’s main LNGproducer after Qatar.

The nation’s eventual output could almost

quadruple to more than 50 million tonnes per

annum by 2020, with the further expansion

of the NWS and Darwin LNG projects, and

with around 10 other ventures under

development or planned for the current 160

trillion cubic feet of gas discovered.

These include five new traditional LNG

projects with land-based liquefaction

plants and three coal-seam gas LNG

projects. Floating liquefaction is also seen

as a certain starter offshore Australia in

the next few years.

Australia is also reaping the benefits of

the new price environment in LNG over

the last couple of years.

Recent Asian LNG contracts are at or

close to crude oil parity in a seller’s market.

Most current long-term contracts contain

regular price reopeners because previous

LNG contracts were negotiated at lower

prevailing crude prices.

Huge reservesAccording to latest government figures,

Australia’s commodity production provides

huge reserves close to 40 per cent of export

income.

The local commodity giant BHP Billiton

and oil and gas companies like Woodside

Petroleum and Santos have joined with

international energy companies to push

ahead with LNG ventures in Australia.

Their project development plans are

underpinned by recent natural gas

discoveries and an abundance of potential.

BHP, for example, says its number one

priority is to expand its LNG and natural gas

business in Australia the same way it has

expanded oil output in the Gulf of Mexico.

The company’s Australian Scarborough

and Thebe gas discoveries off the

northwest coast, as well as the Browse

LNG project, will help expand LNG

output post-2013, said BHP Chief

Executive J. Michael Yeager.

He said BHP was in talks with the

NWS venture and others in Western

Australia on the possible processing of

gas from Scarborough.

BHP has a one-sixth stake in the

Woodside-operated NWS venture, which

is expanding LNG capacity to 15.9

MTPA when Train 5 comes on stream

later this year.

The undeveloped Scarborough field, half-

owned by Exxon Mobil Corp., is the largest

single discovery in BHP's portfolio, while the

Thebe discovery, made last year, is the

company's biggest find in the past five years.

“You're going to see us try to move

heaven and earth to get those projects

crystallized, formed up and get them going

forward,” Yeager said at a recent briefing.

“If we have a number-one priority, it is to

do on the LNG side what we've been able

to do in the Gulf of Mexico.”

The Woodside-operated Browse LNG

project in which BHP has a stake, may

cost between $20 billion and $30 billion

to develop, according to Yeager.

He said BHP and Exxon may decide

within a year how best to develop the

Scarborough field.

Four options are being considered,

including a floating LNG project, a

standalone project, or sending the gas for

processing through the North West Shelf

venture or other companies such as

Chevron Corp. that are seeking third-

party gas for LNG, he said.

The Thebe discovery, holding between 2

trillion and 3 trillion cubic feet of recoverable

gas, is 100 percent owned by BHP and is “a

big shot in the arm”' for the company's

Australia's natural gas resources make it a leading LNG nation with additional prospects for coal-seam gas

LNG Journal Editor, John McKay

p1-14:LNG 3 06/06/2008 11:46 Page 1

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

AUSTRALIAN LNG

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journal

The World’s Leading LNG publication

growth prospects in gas, Yeager said.

While Yeager’s attitude reflects the

can-do nature of the Australian energy

companies, their international partners

and Australia’s federal and state

governments, other less stable countries

with LNG potential are failing to

monetize their natural gas assets for

reasons of resource nationalism.

Another concern among LNG investors in

some countries would be the dangers of asset

seizure through bureaucratic blockage.

In the development of its LNG industry,

Australia has also mostly resolved the key

issue of local energy supplies competing

with the urge to cash in on high energy

prices by exporting as much as possible.

An element of this issue is reflected in

the recent announcement of the Western

Australian state government to reserve

15 per cent of the gas reserves in a

particular gas field for domestic use.

Western Australia is keen to retain

sufficient gas supplies for domestic use

into the long term, while encouraging

investors and energy companies with a

favourable and safe business climate.

According to the most recent

government figures, Western Australia

presently accounts for about 35 per cent

of the nation’s domestic gas demand.

However, there is still a very healthy

natural gas reserves-to-production ratio

in the region in excess of 100 years.

The LNG export market is presently

supplied from the NWS and more

recently from Bayu-Undan, processed at

Darwin LNG, owned by industry pioneer

company ConocoPhillips.

Speaking at a conference last month

in Texas organized by energy pricing

company Platts, senior ConocoPhillips

LNG executive Darren Jones was bullish

about global supply and liquefaction

development, particularly in Australia.

Jones said the company was optimistic

about future LNG supplies being around

450 MTPA by 2020, with the US major

considering an expansion of its Darwin

LNG plant in northern Australia.

“Committed projects in the Pacific

Basin should supply 30 MTPA and

probable projects should make that total

rise to 49 MTPA by 2017,” Jones said.

Australia’s LNG supply additions to

the global total will include: NWS Train

5, 4.2 MTPA by 2008; Pluto LNG Train 1,

4.8 MTPA by 2011; Gorgon LNG, 15

MTPA by 2015; Browse LNG, 10 MTPA

by 2013; Ichthys LNG 7.6 MTPA by 2014;

and Greater Sunrise, 5 MTPA by 2015.

While much credit goes to Woodside

and its partners for the great success of

the NWS project, ConocoPhillips still has

expansion plans for Darwin LNG that

receives feed gas from the Bayu-Undan

field discovered in 1995.

First cargoes were delivered in 2006

and the main customers are Tokyo

Electric and Tokyo Gas Co. ConocoPhillips

has sold LNG to Japan since the 1960s

from its small plant in Alaska.

The company also benefits in the

industry from its Optimized Cascade

SMProcess for liquefaction.

While Japanese utilities, and lately

China, have been Australia’s main LNG

customers the Japanese are also investors

in the Australian LNG value chain.

The Bayu-Undan field exploited by

ConocoPhillips and its partners lies

between East Timor and Australia, about

500 kilometres north-west of Darwin.

The development of Bayu-Undan was

undertaken in two stages. The initial

stage was the condensate stripping gas

recycle phase. Condensate production

began at Bayu-Undan in February 2004

at the rate of some 50,000 barrels per day

with a build up to 110,000 bbl/d by the

third quarter of 2004.

The second stage of the LNG

development involved the construction of

a pipeline from the gas field to the LNG

plant in Darwin harbour.

The first LNG cargo was shipped in

February 2006. Capacity of the plant is

3.24 MTPA. ConocoPhillips is the

operator with more than a 50 percent

stake, but other minority partners

include Santos of Australia, Italy’s ENI,

Japan’s INPEX, Tokyo Electric power Co.

and Tokyo Gas.

Bayu-Undan had initial published

reserves of around 400 million barrels of

condensate and LPG and 3.4 trillion

cubic feet of natural gas.

The NWS project is Australia’s largest

resources project involving some A$19

billion of capital expenditure to date.

Other Australian gas fields earmarked

for LNG development include: Greater

Gorgon, Pluto, Browse Gas, Pilbara LNG,

Greater Sunrise.

The Greater Gorgon fields located to

the south west and west of the NWS, and

including the massive Jansz field,

contains somewhere in the order of 40 tcf,

currently representing some 25 per cent

of Australia’s total gas resources,

according to government figures.

Gorgon LNG, a joint venture between

operator Chevron, Royal Dutch Shell and

ExxonMobil. plans to construct an LNG

plant at Barrow Island with three Trains

each producing 5 MTPA.

The Gorgon natural gas fields are

located about 130 kilometers off the

north-west coast of Western Australia.

Last year a decision was made by the

partners to pursue a scope of three Trains

instead of two to help improve the project

economics and to address rising industry

cost pressures.

Australian projects are similar in

sourcing scope for contractors elsewhere

in the world. Chevron said in its latest

briefing about Gorgon that the project

was committed to providing full, fair and

reasonable opportunity for Australian

industry to supply goods and services and

is working hard to ensure that local

content opportunities for local

contractors are realized.

The Kellogg Joint Venture is the

downstream contractor for Gorgon and is an

unincorporated partnership between KBR

of the US, JGC Corp. of Japan, and Clough

Projects Australia and Hatch Associates.

The downstream component of the

project includes the front-end engineering

and design for the project’s gas processing

and export facilities on Barrow Island.

The Gorgon project is utilizing the

vendor identification services of the

Industry Capability Network of Western

Australia to provide qualified

information on Australian suppliers.

Certain structures may be fabricated in

Australia where practicable, Chevron said.

“We look to maximize Australian

opportunities and hope to see Australian

industry participate and grow its ability

to engage in the subsea development

area,” said Chevron’s Gorgon General

Manager Colin Beckett.

The environmental assessment

process for the expanded Gorgon LNG

scope started in February 2008 when the

revision to the already approved two 5

MTPA Trains was formally submitted to

the Western Australian Environmental

Protection Authority.

The EPA’s decision – which was

advertised in March and received no

objections – set the level of assessment at

Public Environmental Review with an

eight-week public review period.

Beckett said the project team would

continue to work with the state and

Australian governments and other

stakeholders as the expanded scope of

Gorgon LNG progressed through the

approval process.

Woodside is fast-tracking development

of its 100 per cent-owned Pluto gas field

located to the south west of the NWS.

The project is based on the

development of the Pluto and Xena gas

p1-14:LNG 3 06/06/2008 11:46 Page 2

Complex, remote LNG project.Community & environment to sustain.Reputations & revenues to consider.

One looming deadline to meet.

Got a plan? We do.

For more information, email lng@kbr.com or visit www.kbr.com/lng.Interested in being part of our plan? If so, visit www.kbr.com/careers.KO8036 © 2008, KBR Inc., All Rights Reserved

p1-14:LNG 3 06/06/2008 11:46 Page 3

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

AUSTRALIAN LNG

fields with reserves of around 5 tcf. First

LNG is scheduled to be produced in 2010.

Agreements have been reached with

two Japanese companies to supply up to

3.75 MTPA for at least 15 years in

addition to the processing of gas for the

Western Australian market. The project

has approved funding of up to A$11.2

billion.

Pluto LNG onshore contracts

Foster Wheeler WorleyParsons - FEED

and EPCM

� BGC - storage and export site preparation

� Leighton Contractors - LNG train site

preparation

� CB&I - storage tank construction

� Boskalis – dredging

� Ngarda Alliance - constructing Gap

Ridge Village

� Sino-Thai P&I - module fabrication in

Thailand

Pluto LNG offshore contracts

EOS (WorleyParsons, Kellogg Brown

Root JV) – FEED and production system

engineering

� JP Kenny, Atteris - flowlines, trunkline

� Bredero Shaw - pipe coating

� FMC - subsea hardware

� Allseas - trunkline and flowline

installation

� Mitsui and Co - line pipe

� Shenzhen Chiwan Sembawang -

jacket fabrication

� Rumania - topsides fabrication in

Malaysia

� McDermott Industries - platform

There are also a number of major gas

fields (Torosa, Brecknock and Calliance)

located in the Browse Basin, located some

350 kilometres off the north western

coastline from Derby in the Kimberley

region of remote northern Western

Australia.

These fields are of the order of 800

kilometres north-east from the major

fields of the NWS.

The development of these fields is

being assessed by the Browse LNG

consortium consisting of Woodside, BP,

BHP, Chevron and Shell.

Additionally, the development of the

Ichthys field in the Browse basin is under

consideration by a joint venture of the

Japanese company Inpex and the

France’s Total.

The resources of both these fields are

very large. For example, the Torosa,

Brecknock and Calliance fields contain in

the order of 20 tcf of gas - around 20

times Australia’s total present annual

gas consumption - and Ichthys contains

about 10 tcf.

The fields also contain limited

amounts of condensate. The proposals to

develop these gas fields are in the very

early stages and production is unlikely to

begin in either of these fields before 2012.

The federal and Western Australian

governments are currently assessing

whether Browse Basin gas LNG

developments should operate out of a

single industrial hub at a suitable site in

the Kimberley region.

Possible benefits could include site

selection with least disturbance of

pristine areas and better efficiency in

terms of environmental impact

assessments and project approval.

The Troubador and Sunrise fields,

known jointly as the Greater Sunrise field,

are located offshore in the Bonaparte Basin,

350 kilometres north-west of Darwin.

The Greater Sunrise field contains an

estimated 295 million barrels of

condensate and 8.4 tcf of gas.

Development of these fields is on hold

pending further economic assessment.

The Sunrise LNG project planned by

Woodside was on the agenda when

Australian Resources Minister Martin

Ferguson visited East Timor last month.

Sunrise could become the first major

offshore LNG venture using Shell’s

FLNG technology that is currently under

development. Shell is also one of the

Sunrise shareholders.

An LNG project based on Shell FLNG

technology would remove potential

political delays in the Sunrise venture as

there would be no need for an onshore

LNG plant in East Timor nor in

Australia, analysts said.

Floating LNG not only might solve

some of the political issues surrounding

development of gas assets in the joint

petroleum development area of the Timor

Sea, but also might substantially reduce

the capital costs of Greater Sunrise,

industry executives said.

Floating LNG incorporates the

replacement of three elements of a

conventional LNG scheme, namely the

production platform, the pipeline to bring

gas ashore and all the onshore facilities

for liquefaction and loading.

Instead, using sub-sea production, the

offshore gas is produced directly to a

barge moored above the gas field, with

the barge supporting a compact

liquefaction plant and storage facility.

The Timor Sea treaty between Australia

and East Timor, which came into force in

April 2004, provides the underpinnings

for regulatory and legal certainty for

investment in oil and gas developments.

The treaty establishes that the Timor

Sea Designated Authority is administered

by the Australian government.

Australia has limited crude oil but is

relatively well endowed with natural gas

resources. The natural gas industry has

shown remarkable growth - both the

domestic and export sectors - over the last

few decades and this is projected to continue.

The bulk of Australia’s gas resources

are located long distances from the eastern

Australian markets. These are offshore

northwest Western Australia (Carnarvon

and Browse basins) and in the Timor Sea

to the north of Australia (Bonaparte

Basin). Because of the uneven distribution

of our gas resources it had been thought

that gas would need to be piped from these

fields when the closer smaller eastern

fields run down prior to 2020.

The above scenario is now less likely

with the development of newer gas fields

in the Gippsland, Bass and Otway Basins

located offshore in southern Victoria.

Furthermore, there has been rapid

development of coal seam gas reserves in

Queensland and New South Wales with

the potential to become a major source of

gas for eastern Australia.

The natural gas export sector is

presently supplied from the North West

Shelf and Bayu-Undan, Darwin.

Additional export volumes are expected

from the North West Shelf in late 2008

and thereafter from a number of new

ventures including Greater Gorgon,

Pluto, Pilbara LNG, and Browse Gas all

in Western Australia, and coal seam gas

field developments in Queensland and

New South Wales.

A recurring question in natural resource

use and development is: why export a

commodity with an important domestic

use, especially with gas exports projected

to increase to around 60 per cent of

production by 2020. The answer invariably

relates to economics and the adequacy of

the resource base to provide for domestic

use into the foreseeable future.

Natural gas as an energy source has

significant environmental benefits over

both coal and oil in terms of lower

greenhouse gas and other emissions. This

aspect will be of considerable advantage

in the further promotion of natural gas

use and Australia’s energy future.

Natural gas remains a cheap energy

source in Australia when compared to the

United States and Europe. However,

wholesale gas prices have generally

trended upwards in the last few years,

especially in Western Australia.

Implementation of newer gas

regulatory processes has been protracted

although considerable progress has been

made in recent times. The present Gas

Code will be replaced with the National

Gas Law and National Gas Rules.

Regulation will be simplified with a

single Australian Energy Regulator.

Coal seam gasThe rapidly developing coal seam gas

(CSG) industry is adding to Australia’s

known economic gas resources.

Importantly, these gas sources are

relatively close to the major centres of

population in eastern Australia. The

development of these gas sources could

delay the need for gas to be piped from

Western and Northern Australia for

many years and possibly decades to come.

Whilst the outlined reserves and

resources of coal seam gas are still

relatively modest, there has been strong

growth in this sector of the gas industry

with year on year production increases,

beginning with 2 petajoules (PJ)/y in

1994 and growing to 45PJ/y in 2004.

Gas associated with coal mining was long

regarded as a major hazard causing explos-

ions in underground coal mining operations.

These gas accumulations were often

Australian Gas Consumption and LNG Export Forecast

p1-14:LNG 3 06/06/2008 11:46 Page 4

vented where practical and subsequently

wasted. Furthermore, this gas is a highly

intensive greenhouse gas, with a global

warming potential some 21 times higher

than carbon dioxide.

Modern technology and

the realisation that such gas

can be a valuable energy

resource have led to the

development of this industry.

CSG - often referred to as

coal seam methane (CSM)

- is naturally occurring

methane gas in coal seams.

The associated gas in coal

has been absorbed onto the

grain faces and micro-pores of

the coal during the geological

thermal maturation process

of coalification. CSG

resources contained within

the Queensland and New

South Wales coal reserves

and resources are located

fairly close to large potential

markets in eastern Australia.

The successful development

of CSG fields n SANTOS is

claiming "first mover" status

in the race to build the world's

first liquefied natural gas

project while conceding there

is also room for a rival project

backed by British Gas and

Queensland Gas.

When Queensland Gas

announced earlier this year

that it had formed an alliance

with BG to build an LNG

plant at Gladstone in

central Queensland, its chief

executive Richard Cottee said

he expected all LNG projects

to eventually "migrate to one".

There are four projects on

the drawing board to pump

coal seam methane gas from

the Surat Basin on the

western Darling Downs

through to Gladstone and

turn it into liquid for export,

with Santos and Queensland

Gas/BG the frontrunners.

When Santos proposed its

$7.7 billion project in July

last year it claimed it would

be producing LNG for export

by 2014, but Queensland

Gas says its plant will be

producing LNG by 2013.

Santos has the second-

largest quantity of natural

gas after Origin, which is the

LNG journal • June 2008 • 5

AUSTRALIAN LNG

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Origin's gas reserves are necess-ary for the

QGC/BG project to proceed.

But Santos has increased its tonnage

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p1-14:LNG 3 06/06/2008 11:46 Page 5

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

VALUE CHAIN

Figure 1 – Isle of Grain Terminal

Commercial engineering of LNG value chain merits more attentionNeil Wragg and David Haynes, Advantica Group

What is the optimum LNG project design?

The question usually has different

answers depending on who you ask.

Engineers will want certain technical

features such as maximum storage,

certainty in design specifications and a

narrow range of composition while

commercial team members will see

the value in flexibility and the ability

to arbitrage.

Project management and the

financiers’ interest will be in schedule

and cost.

There are many management methods

used to bring these diverse opinions to a

consistent and achievable facility design,

but is there a tool available that will

measure and compare all these criteria to

enable the optimum design to be found?

Advantica has been developing a

concept called “Commercial Engineering”

which attempts to put numbers to many

of the engineering and commercial

aspects of projects.

Using Monte Carlo simulation, a risk

profile for a project can be produced

which values the range of possible project

outputs from worst case through to

“normal” operations. This paper will

attempt to explain, using project case

studies, the application and power of

the technique.

To analyse an LNG project, one or

more parts of the LNG supply chain may

need to be analysed.

For the simplest models, only the LNG

liquefaction plant or import terminal

needs to be modelled. This is classic

availability modelling. The modelling is

designed to analyse equipment sparing

philosophies to enable a certain level of

production to be guaranteed to meet

contractual commitments; this could be

on an hourly, daily or annual basis.

The simulation is straight forward;

however, LNG industry-specific

reliability data, the underlying basis of

the assessment, is often difficult to find.

Liquefaction plants, in particular, publish

little of their operating performance,

making performance benchmarking

difficult to achieve.

However, most of the risk and the

potential value in an availability

simulation involves correctly sizing the

LNG storage tanks which inevitably means

that LNG ships need to be investigated.

Again, there is little data on ship

physical performance. The main

parameter that needs to be considered is

much more difficult to define, the

weather. Port delays resulting from tides,

strong winds, large waves or fog can have

a considerable impact on terminal

operations and may define the amount of

LNG storage required.

For onshore facilities, wave impacts

can sometimes be mitigated by the use of

a breakwater. The costs associated with

marine protection may eclipse the

amount of expenditure required on those

expensive LNG tanks.

In the nascent offshore world of FSRUs

and FPSOs no such protection is available

and weather impacts and the stored LNG

volumes to mitigate them become

disproportionately more important.

Modelling can be extended further to

assess the distribution of ship voyage

times and the impacts of weather and

other marine traffic on fleet size and

project performance.

SolutionsThe UK gas market has recently

undergone, and will continue to undergo,

a change in its gas supply and will no

longer be self sufficient in natural gas.

Demand will increasingly be met by

importing gas via interconnecting

pipelines and through LNG. There has

been an LNG peak shaving facility at the

Isle of Grain, a remote location but within

50 kilometres of London, since 1981.

In 2000, National Grid decided to

rejuvenate an old oil berth and to convert

and extend the existing peak shaving

equipment into an LNG import terminal.

Since that time two additional project

phases have occurred, each expanding

the facility significantly.

The success of the project depended on

many factors including system design and

life extension, operational strategy,

equipment reliability and supply contracts.

A key consideration was ensuring that the

facility will deliver the required business

performance once in operation.

Advantica was involved in the

modelling and risk analysis of all three

phases of the Grain project. The nature

of the risks and the role of availability

modelling have changed considerably

over this time and demonstrates many of

the impacts of Commercial Engineering.

Advantica was trying simultaneously to

achieve two goals:

� Minimisation of capital investment

� Minimisation of commercial risk (or

protection of minimum revenues)

The initial phase of the project was all

about minimizing capital expenditure

while ensuring minimal contractual

penalties. The key decision was how

much throughput could be sold to LNG

shippers. This modelling was performed

from three aspects:

1. What equipment needed replacing or

additional units purchased?

2. At what gas throughput was the

existing storage adequate (as project

schedules would not allow additional

tanks to be built)?

3. What technical terms should be

included in the tolling agreements to

protect the terminal owner?

An availability model of the whole LNG

terminal quickly demonstrated that the

current ratings of the LNG plant could be

expanded to 125 percent of nameplate

capacity without significant loss of service,

but that increasing the throughput to 166

percent or 183 percent of rated capacity

could attract significant penalties from

terminal users if additional capital

investment was not sanctioned.

Different investment scenarios were

developed to investigate their impact on

Figure 2 - What can a terminal handle?

p1-14:LNG 3 06/06/2008 11:46 Page 6

p1-14:LNG 3 06/06/2008 11:46 Page 7

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

VALUE CHAIN

availability and therefore overall project

commercial performance. For the 166

percent throughput scenario an economic

investment scenario could be justified.

The impact of the additional gas

throughput was the need to turnaround

LNG tankers more frequently.

This results in the LNG storage tanks

being cycled more quickly. The impact of

this on the limited existing storage

capacity was that, occasionally, the tanks

were too full to allow the unloading of an

LNG carrier in the allowed contractual

timescale.

Demurrage would be payable or,

alternatively, shipping slots would need

to be cancelled with an appropriate

penalty charge.

To avoid these penalties, an

additional storage tank would be

required; an expensive technical

mitigation and one that, through

negotiation, might be avoided

commercially in the tolling agreement.

The Grain expansion, started in

2004/5 (now nearing completion),

presented a different set of issues.

The Isle of Grain site is large so any

amount of equipment and storage tanks

can be accommodated provided that this

is financially attractive. Tolling

agreements for the second phase capacity

were quickly completed and were able to

cover the installation of 3 x 190,000 cubic

metres storage tanks, with additional

pumps and vaporisers.

These installations were analysed

using availability modelling to confirm

that no unacceptable risks were being

taken and whether targeted equipment/

Capex reductions could be made.

The only facility that needed to

operate unaltered from Phase 1 was the

jetty, which now had to accommodate

more than twice the number of vessels

seen in Phase 1.

Grain is a good marine location and

has very little in the way of access

restrictions (some current limits) but can

be prone to significant wind effects.

The modelling confirmed that, even

with in excess of 150 LNG ships calling

at the terminal annually, there was only

a low risk of any of these berthing slots

being cancelled.

Furthermore, demurrage penalties

were outweighed by the revenue

associated with the additional ships, even

in the most pessimistic scenarios.

Interestingly, the main contributors to

berth downtime were not natural

phenomena (i.e. weather or tidal

limitations), but the physical inability to

unload fast enough due to equipment

failure, either on the ship or on the berth.

The second expansion phase (recently

started construction) required further

ships to be accommodated. LNG ship

sizes also increased over this period,

which included the development of the

Qatari Q-Flex and Q-Max ships.

These larger vessels complicated the

analysis since, due to their larger

draughts, they were subject to tidal

restrictions during the transit to and

from the terminal. The extra ships and

their additional size demanded the

construction of a second jetty to reduce

the impact of transit delays.

Provision of an additional jetty enabled

a second ship to berth and prepare for

unloading whilst another ship continued

to be unloaded on the first jetty.

LNG salesThird Party Access (TPA) to an LNG

import terminal is the regulated norm in

Europe. The commercial arrangements

need to be written in such a way so that

no participant in the terminal is

advantaged or disadvantaged compared to

any other, often regardless of their

investment or throughput in the terminal.

Advantica has been working with a

major European company to assist in the

development of the commercial strategy

for a proposed LNG import terminal, and

to test their practicality and risk profile.

The terminal development has two

features that complicate modelling:

� Shipping delays occur very late in the

journey or on entry to the port

� Storage inventories are limited by

local authority planning/zoning

consents

Normally regasification capacity is a

contentious issue. All the shippers want

the rights to send out when the market

price peaks and none of them wish to

send out when it is at its nadir.

However, regasification plant is

relatively inexpensive compared to

storage and berth facilities so additional

capacity can often be justified to provide

shipper upside until other constraints

such as offtake pipeline capacity come to

the fore.

The gas nomination send-out system

was originally designed to send out all

the LNG/gas from one carrier prior to the

arrival of the next vessel.

This suits the terminal operator

extremely well as he can almost

guarantee that there will be sufficient

tank space to unload the next ship.

However, it can be argued that it

penalises a small LNG shipper as its

volume must be sent to the market (or

gas storage elsewhere) in very short-

duration but high-volume batches.

A larger shipper feels less pain as its

cargoes arrive more frequently and the

send-out profile, although “spiky”, is more

continuous.

Aggregating the LNG of all terminal

users and sending them out over a longer

period, say a week or two, levels the

playing field but at the cost of more

vaporisers and either larger storage

tanks or greater working capacity.

Availability modelling has been used

to test these different send-out time

periods against maximum storage

volumes and send-out capacity.

Figure 3 - How much throughput to sell?

Figure 4 - Investment scenarios

Figure 5 – Storage Tank Issues

p1-14:LNG 3 06/06/2008 12:00 Page 8

As with most TPA contracts, this

project involved the purchase or award

of “berthing slots”. LNG voyage

modelling was conducted to examine the

likely delay profile of LNG

vessels arriving at the

anchorage/pilot station

and then transiting into

the port.

The result was a wide

range of delay times, with

the most significant delays

from both traffic and

weather occurring in the

last 48 hours of the voyage,

allowing no time for the

vessel to catch up on its

original schedule.

This had implications for

the Notice of Readiness

(NOR) clauses in the

contract and on the

operation of the terminal.

A late ship would be able

to unload but potentially

has a knock-on effect on the

next ship and its ability to

unload. Deciding how late a

ship can arrive and still be

unloaded is a key decision.

With a fixed gas

nominations system there

is less opportunity to

increase send-out to

rapidly create space for the

next tanker. The second

tanker may then have to

wait at the expense of the

terminal operator.

Various NOR rules were

evaluated simultaneously

with the gas nominations

rules to fix a NOR window

and start time which

minimised ship waiting

(and terminal penalties)

and maximised the ability

to unload late ships.

MaximiserevenueThe establishment of

portfolio suppliers able and

willing to supply LNG to a

range of import terminals

from a range of liquefaction

plants, normally on the

basis of price, has been a

key development in the

LNG industry over the last

five years.

Such diverse cargo

deliveries have included

vessels moving LNG from Nigeria and

Trinidad to Japan (8-10,000 nautical

miles). Commercially the rationale for

this type of business is clear, better

profitability. Most LNG purchase

agreements now include diversion

clauses allowing, if not encouraging,

this business.

The immediate question is how should

an LNG facility be designed to have

access to this upside without investing

excessive capital?

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delays to occur in the load and off load

ports and the model is able to predict

whether a ship would be available to load

the next cargo before the LNG tanks

over-top and the liquefaction plant needs

to be turned down or stopped.

Ship loading and destination schedules

can be changed to perform sensitivity

analyses on the robustness of the LNG

trades for a given level of LNG storage.

The model so far includes a range of

destinations in Europe and the Americas

and is currently examining the inclusion

of LNG terminals in the Far East.

Using this type of supply chain

“commercial” model, sensitivities can also

be carried out to examine the potential

benefits of periodically selling cargoes on

the spot market, over and above the base

load contractual commitment.

Understand securityThe Isle of Grain case study provides an

insight into the commercial operation of

an onshore terminal.

The LNG industry has ordered its first

two Floating Storage and Regasification

Units (FSRUs) and more look set to

Advantica has been working for a

major international oil company to try an

address these issues for a green field

LNG liquefaction development.

The availability of the liquefaction

plant itself can be modelled (using

similar techniques to those described for

Isle of Grain) to generate a probabilistic

LNG production profile, based on a given

supply chain throughput.

Combining the LNG production profile

with a Monte Carlo model of the ship

arrivals and loading operations allowed the

project to make a key investment decision:

“How many storage tanks should be

built and what size should they be to

minimise disruptions to the LNG supply

chain?”

The second key investment decision

the project has to make is:

“How many LNG tankers should the

project own (or long-term charter)?

In this instance, the supply chain

model is incorporating each ship’s voyage

plan and assessing, based on seasonal

weather data, the likelihood of a ship

arriving at the terminal on schedule.

Combine this with the potential for

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

VALUE CHAIN

follow. Many of the FSRUs under

consideration are for smaller or island

markets where the vessel represents the

sole gas supply system.

A back-up fuel supply may be

available, particularly for power

generation-led projects, but diesel is

typically more expensive than LNG and

has higher maintenance costs for gas

turbine type machinery.

Fines for abusing environmental

consents may also be applied. The issue

of security of supply and, hence, facility

availability therefore becomes paramount.

Availability in this context has two

elements; firstly plant availability, the

nuts and bolts of equipment operation

and maintenance, and secondly berthing

availability.

The critical difference between

onshore and offshore is the lack of the

usual technical mitigations; storage

volumes and breakwaters.

FSRUs are normally sited in water

depths that make the construction of

breakwaters or other protective facilities

uneconomic. The FSRU will, therefore,

see the full force of Mother Nature.

Site selection is critical with any

shelter from distant headlands or nearby

islands a potential boon. It is not all bad

news, it is easier to moor one vessel to

another (side by side) than a vessel to a

fixed structure such as a jetty.

The two ships can move together

limiting the impact of waves and wind.

The issue is the initial berthing, the

moment when the two vessels first touch.

The industry is working hard to

understand the issues and develop

guidelines for operating limits but at the

moment the limits are somewhat vague

and three categories based on wave size

are suggested.

� Conventional protected berth (the

norm for onshore)

� Exposed berth (for example Brunei)

� Expected limit for tug operations

Table 1 provides example availability

figures for an FSRU to accept an LNG

carrier in different wave states. This

example is taken from a recent

Advantica FSRU project for a relatively

benign sea area.

It quickly becomes obvious that, for

FSRUs to be economic, berthing manoeu-

vres must be accomplished in higher sea

states than for a conventional terminal.

Even at claimed maximum tug

operating limits, berth availabilities only

start to approach those regularly

achieved onshore.

The mitigation for this lack of berthing

availability is storage margin, i.e. the

amount stored on the FSRU less that

carried on the LNG tanker serving it.

Most of the currently envisaged

FSRUs, to achieve aggressive schedule,

are conversions of older LNG tankers

which have smaller cargo volumes,

138,000 cubic metres or below.

The bulk of the LNG carrier fleet is

also of this size so storage margins can be

very limited. Normal onshore mitigations

are therefore of little value and

commercial mitigations covering

alternative fuels are likely to be required.

Advantica modelingAdvantica has successfully used

availability modeling throughout the

LNG supply chain. Traditional

availability modeling is useful to

engineers to provide an estimate of

performance for an LNG facility design.

However, availability modeling can do

much more if the commercial or business

aspects of the problem can be analyzed

alongside the design.

The assessment of multiple segments

of the LNG supply chain (i.e. storage,

load/unload, transit) is often necessary

for a more complete solution.

“Commercial Engineering” has the

potential to maximize project

performance by allowing both

commercial and technical mitigation of a

particular project issue to be considered.

The “Commercial Engineering”

methodology, although able to make an

impact throughout the life-cycle of a

project, is best applied during the

conceptual and feasibility phases as this

maximizes the scope for alternative

solutions to be considered. �

Neil Wragg is Advantica’s SeniorConsultant, Asset Performance. Email:neil.wragg@advanticagroup.com

David Haynes, is Advantica’s Principal LNGConsultant. Email:david.haynes@advanticagroup.com

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p1-14:LNG 3 06/06/2008 11:48 Page 11

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

PROJECT RELATIONSHIPS

LNG project relationships change asNOCs gain more contract leverageNick Prowse, a partner in law firm Norton Rose LLP, presents the first of a two-part series on perfecting LNG joint venture contracts

The critical issues between NationalOil Companies (NOCs) andinternational oil companies (IOCs) injoint venture LNG projects are valueextraction, control, added value tothe host country and incentives andinvestment protection for the foreigninvestors.

These are the main drivers behind

the anatomy of a typical LNG project

today and it is these issues that are

being fiercely contested by NOCs and

IOCs during negotiation of the many

LNG ventures currently under

development.

The potential investors and

stakeholders in an LNG chain will each

bring their different assets to the

negotiating table.

NOCs will bring the principal asset -

natural gas – and IOCs will offer a

variety of assets, including established

market positions, technical expertise,

equipment and skilled personnel,

technology licences and access to prime

natural gas markets.

The extent to which each party

requires the other to complete an LNG

chain will have a strong impact on the

relative strengths of the bargaining

positions.

These strengths will no doubt vary at

different stages of the LNG chain. In the

current market, we are seeing NOCs

gaining more

access along

the

chain

because of

their desire to exercise control and share

rewards along the chain.

Previously NOCs were most visible

upstream, where the initial capital

investment from investors is typically

required.

Key demandsHolders of large natural gas reserves can

also demand that their IOC partners

provide project development and

technological expertise without being full

asset partners, therefore limiting

potential upside for the IOCs.

In multiple-Train projects NOCs are

also benefiting by using their experiences

of Phase 1 Train development to seek

improvements in the terms of any new

contracts presented.

The most successful LNG projects are

those that strike the right balance along

the chain. However, some potential LNG

projects have struggled from conflicts of

interest from the outset and never

reached a final investment decision.

Currently, the biggest problem in the

LNG industry is a shortage of LNG

supply caused by delayed liquefaction

projects.

Making projects happen and striking

the right balance between NOCs and

IOCs in the current environment is

especially difficult, given rising

construction costs and a shortage in the

availability of skilled and experienced

contractors.

Even if an LNG project

reaches commercial

close, there is a never-

ending balancing

act between the

objectives of NOCs

and IOCs over

the life of the

project as new

issues arise and

circumstances

change.

Given today’s

complex commercial

arrangements which

make up an LNG chain, this

continuing balancing act is often

difficult to manage. In particular, NOCs

are seeking ever better terms frequently

causing problems in the context of

expansions.

The final structure of each particular

project will be determined by the positions

of the parties on these critical issues.

Value extractionNOCs typically seek to maximise their

return from the development of their

natural resources and also from any

direct investment they may make in the

LNG chain.

IOCs need to develop LNG chains in a

manner that, among other things, seeks

to maximise shareholder return.

Traditionally, IOCs have been involved

in more than one link in the LNG chain.

This gave IOCs the opportunity to

extract value from the chain in a

number of places.

More recently, NOCs have been

moving down the LNG chain to realise

value downstream as well as upstream.

The issue of value extraction gives rise

to a number of financial tensions between

NOCs and IOCs and is, perhaps, the most

critical issue for NOCs and IOCs

developing a LNG project today.

There are a number of places along the

chain where NOCs and IOCs may extract

value. At the final link, the LNG will be

turned back into gas and sold in the

destination markets.

Ideally, those sales proceeds will be

sufficient to make their way back up the

chain and return a profit to each

participant in the chain, otherwise not all

participants will be satisfied.

The number of places where IOCs

and NOCs may extract value will be

determined by the extent to which

they are vertically integrated. Look,

for example, at the following links in

the chain:

� Upstream assets: are they involved in

natural gas production, transportation

and gas sales to the liquefaction plant

in the host state and therefore able to

extract value upstream?

� Liquefaction assets: who is involved in

liquefaction and LNG sales and

therefore able to extract value through

the liquefaction plant project

company?

� LNG carriers: are all parties involved

in delivering from the host country to

destination markets and therefore

able to see revenue from the provision

of shipping transportation services?

� Regasification: who has capacity at the

import terminal and ultimately

control over the sale of natural gas in

destination markets?

UpstreamThe extent to which value can be realised

upstream will be dictated by the

exploration and production licensing

regime operated by the host country.

As a practical matter, this part of the

LNG chain affords little scope for

structuring or negotiation. The IOCs are,

on the whole, at the mercy of the NOCs

and have to operate predominantly on

their terms.

In some countries, all the

hydrocarbons may be owned by the NOC

at the point of sale to the liquefaction

plant.

This is typically the case in countries

which operate a service contract or buy-

back contract regime, where foreign

investors in the upstream development

are paid for their services rather than

given a share of production.

Here, the NOC will be the seller of all

the gas to the liquefaction plant. There

will then be obvious tensions as to the

price at which gas should be sold to the

liquefaction plant.

Should this be at market rates, or

instead at artificially low prices to allow

the liquefaction company to increase its

profits? This will need to be negotiated

on a case-by-case basis and is obviously a

sensitive issue.

In host states which operate a

production sharing agreement regime,

both the NOCs and the IOCs will

typically own their respective shares

of production, as allocated to them at

the “fiscalisation point” in accordance

with the terms of the relevant production

sharing agreement.

The mostsuccessful LNG

projects are thosethat strike theright balance

along the chain.

p1-14:LNG 3 06/06/2008 11:48 Page 12

LNG journal • June 2008 • 13

PROJECT RELATIONSHIPS

Tax and royaltyIn this situation, the NOCs and IOCs

should be more aligned as to the price at

which gas should be sold to the liquefaction

plant as they are both gas

sellers.

At the other end of the

spectrum, in host states

which operate a tax and

royalty regime, the host

state will typically transfer

ownership in all produced

hydrocarbons to the IOCs.

However, no host state

gives up its natural

resources for free and

instead the host state will

realise value through the

levy of taxes and royalty.

Ideally, whichever

upstream licensing

structure is used, the price

at which natural gas is sold

to the liquefaction plant,

whether by the NOC, the

IOCs or both, should be set

at a level which ensures

that the IOCs and NOCs

each earn a fair rate of

return over time.

In reality, however,

NOCs tend to try to tip the

balance very much in their

favour. For example, if you

wish to explore for and

produce hydrocarbons in

various parts of the Middle

East, the only way to do so

is under service or buy-back

contracts.

Buy-back contracts

contain some of the

toughest terms in the world

for foreign investors and

there is currently a trend to

use these more frequently

in the Middle East.

Tough termsAt present, foreign

investors seem to be

prepared to agree to

exploration and production

terms under buy-back

contracts which are

extremely favourable to the

host state, presumably

because competition

amongst foreign investors

for new exploration

opportunities remains

extremely high.

Of course, value

extraction is not the only upstream issue

which is of critical concern to IOCs. One

of the key objectives of any IOC in

relation to a LNG project will be the

ability to book reserves.

This is because failure to find and

book new reserves, thereby replacing

reserves which are currently being

produced, can have a negative impact on

an IOC’s share price.

Buy-back contracts are a major

irritant for IOCs in this respect because

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

PROJECT RELATIONSHIPS

following ways:

(a) Technology licences - Licence fees

may be a lucrative source of value

extraction for foreign investors

providing liquefaction technology,

such as Royal Dutch Shell or

ConocoPhillips;

(b) Co-lending to projects - Not such a

classic case, but one which seems to

be becoming a trend for foreign

investors is co-lending to liquefaction

projects at a level equivalent to

commercial banks and export credit

agencies. This can only be done by

those IOCs with access to the

necessary funds. It does provide

another means for an investor to earn

a return on its investment, or at least

to prevent its return being diluted by

project financing; and

(c) Licence fees - Similarly, NOCs may

extract value through charging

licence fees, port fees, export taxes

and other similar levies in the host

country.

Maintaining control is also an important

issue for the parties. Control can be

derived through participation in the LNG

chain in much the same way as has just

been seen in the context of value

extraction.

The host government will often wish

to ensure that it or the NOC retains

control over the liquefaction plant and

other parts of the LNG chain which it

considers of strategic importance.

In this context, NOCs are increasingly

seeking to maintain more involvement in

or control over the LNG chain. This is

partly related to issues of value

extraction and, in particular, greater

control may help an NOC to prevent

revenue leakage from the chain without

its approval.

In addition, it may also give the NOC

an opportunity to participate in decisions

to realise short-term opportunities such

as selling occasional spot cargoes or

positioning excess production volumes.

This issue of control can obviously give

rise to a number of tensions between

NOCs and IOCs as their interests are

unlikely to be aligned at all times.

We will look at specific legal issues

involving NOCs and investors in Part II

of this article which will be published in

the July edition of the LNG Journal. �

This article is based on a presentation byNick Prowse, Partner at Norton Rose LLP,at the 4th Annual Law of LNG Conferencein Houston, at the Centre for Americanand International Law.

the IOCs are

entitled to a

fee

rather

than a share

of the reserves,

therefore making it

difficult to “book” the reserves.

Moving down the chain,

value may be realised

through the shares which

the NOC and IOCs own in

the liquefaction plant project

company.

The liquefaction plant project

company will need to be a robust and

profitable joint venture, particularly if it

is project-financed. Profits made from

liquefaction will either be re-invested in

the plant or, more likely, distributed to

shareholders.

There is plenty of scope for deal

structuring and risk allocation in and

around liquefaction projects, with at least

two models to choose from for revenue

generation in liquefaction.

SPA structure The first model is a sale and purchase

structure. The gas is sold to the project

company, the project company produces

LNG and the LNG is then sold by the

project company to its off-takers.

Most LNG projects follow this model.

Here, the level of profit will typically

depend on the costs of the liquefaction

plant project company, including the

purchase price of natural gas, and the

price realised for sales of LNG.

For those NOCs which are not

involved downstream beyond the

liquefaction plant, sales of LNG will be

their last opportunity, and in some cases

the primary mechanism, by which they

may extract value from the LNG chain.

Similarly, if the IOCs are not involved

in shipping, regasification or marketing

of natural gas in destination markets,

they will also be seeking

to maximise their return

on any sale of LNG

to third parties

at the LNG

loading arm

in the host

country,

assuming

the sale

is

structured

on a free-

on-board

(FOB) basis.

However,

for those IOCs

which are

involved in the

downstream business,

they may be more interested in

extracting value downstream if this

improves their overall economics.

The second model is a tolling

structure. Here, the liquefaction plant

project company will not buy natural gas

and sell LNG and will typically not have

title to the natural gas or LNG while it is

in its custody and control.

Instead, the project company will be

paid a service fee in return for the

provision of liquefaction and other

services. In a tolling structure the

liquefaction plant project company will

typically take little risk other than its own

operating risk but will, as a consequence,

also earn a lower rate of return.

LNG shippingValue may also be realised in the provision

of LNG shipping services although the

maritime part of the chain can look very

different from project to project.

Some NOCs have long been involved

in the LNG shipping business, such as

Malaysian energy company Petronas

through its majority shareholding in

Malaysia International Shipping Corp.

Others, such as Nigerian National

Petroleum Corp., are involved in LNG

shipping activities through joint ventures

with IOCs. For example, Nigeria LNG

Ltd. has been providing LNG shipping

services through its wholly-owned

subsidiary Bonny Gas Transport (BGT)

for many years.

The BGT structure is essentially an

extension of the liquefaction plant to

enable the project to deliver LNG to its

customers in destination markets on an

ex-ship basis.

Qatar Gas Transport Co., also known

as Nakilat, was established in 2004 by

NOC Qatar Petroleum and others to

ship LNG for its charterers (Qatargas II,

Qatargas 3, Qatargas 4 and Rasgas 3) to

the UK, US and other markets. Other

NOCs are now considering adopting

LNG shipping models similar to the

Qatar 1 model.

There are some tensions between

NOCs and IOCs in this part of the chain

as IOCs, if given a choice, would typically

prefer to use their own, owned or

chartered, LNG carriers. This is for

reasons of both value extraction and

control.

RegasificationValue may also be realised through

shares in the regasification plant project

company and/or capacity rights in the

regasification terminal to the extent

IOCs or NOCs own such shares and/or

have such capacity rights.

However, if the regasification terminal

is owned by a third party then any IOCs

or NOCs seeking to reserve capacity will

try to keep any capacity reservation and

other fees as low as possible to minimise

value leakage.

Value may also be realised upon the

sale of natural gas owned by the NOCs

and IOCs, or any downstream joint

venture, in the destination market.

NOCs are increasingly securing

contracts for the long-term lifting and/or

marketing of LNG and some such as

Qatar Petroleum, Petronas and Angola’s

Sonangol have secured positions in LNG

import terminals in the Atlantic Basin.

Qatar Petroleum, as a consequence of

its upstream partnership with

ExxonMobil, has stakes in ExxonMobil’s

downstream regasification projects.

These include the Adriatic LNG

import facility being constructed offshore

Italy, the South Hook regasification

terminal being completed in the UK, and

a subsidiary of the Qatari company will

have a majority stake the Golden Pass

import facility under construction in the

US state of Texas.

Petronas has a share in the Dragon

LNG import terminal under construction

in the UK, while Sonangol has gained a

stake in the Pascagoula LNG import

terminal planned for the US state of

Mississippi by Chevron Corp., one of its

upstream partners in Angola LNG, the

southwest African nation’s first LNG

project.

Revenue streamsNOCs and IOCs may also extract or at

least seek to maintain value in the

In a tolling structure the liquefaction plantproject company will

typically take little riskother than its own

operating risk but will, as aconsequence, also earn a

lower rate of return.

p1-14:LNG 3 06/06/2008 11:48 Page 14

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STATE-OF-THE-ART FULL MISSION TUG SIMULATOREmphasis on continuous improvement is part of the SVITZER solution. This is also evidenced by ourdevelopment of a state-of-the-art full mission tug simulator. The first of its kind in the towage industry and dedicated to clients of SVITZER. Coupled with our ongoing follow-up programmes and rigorous training of local crews, our clients are ensured conti-nuous high performance at their LNG facilities.

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p15-30:LNG 3 06/06/2008 12:29 Page 1

is based upon the application of

prescriptive requirements, sea-keeping

studies, structural and fatigue analysis of

the structure, containment and station

keeping systems plus a series of overall

risk analysis and special studies. A

number of ABS Guides and Guidance

Notes will be referred to in establishing

compliance for the Teekay floating gas

liquefaction facility, including the ABS

Guide for Building and Classing Offshore

LNG terminals as well following

international standards such as the

International Maritime Organization’s

Gas Code. Specialized required analysis

and technical studies include: mooring

analysis, containment system sloshing

analysis, gas dispersion and heat

radiation analysis; cryogenic liquid

spillage and structural protection study;

vibration studies to analyze impact of the

top side processing facilities on the hull;

as well as other detailed process and

marine systems studies, ABS said.

Teekay, the Vancouver-based shipping

company, is the latest of around a dozen

companies to be involved in developing

floating LNG concepts. Teekay has a fleet

of almost 200 vessels and transports

more than 10 percent of the world’s

seaborne oil, as well as a growing share

of the world’s LNG.

AES Corp.’s planned Sparrows Point

LNG import terminal near the US city of

Baltimore has progressed after the

Federal Energy Regulatory Commission

ruled the facility would have limited

adverse environmental impact. The

FERC issued a draft environmental

impact statement (EIS) for the facility

being developed by AES, a power

company, on the former site of a

Bethlehem Steel shipyard. Sparrows

Point will have an eventual 480,000 cubic

metres of LNG storage and natural gas

send-out capacity of 1.5 billion cubic feet

per day. The advance of the FERC

application for Sparrows Point comes at

a time when other US LNG projects are

being delayed by the developers because

of a global shortage of volumes for

companies not linked to the LNG chain.

A pipeline linked to the project would be

about 88 miles long and run in two states,

from Maryland into the town of Eagle in

Pennsylvania. The EIS made the usual

mitigating measures compulsory and

included findings by the US Coast Guard,

the US Army Corps of Engineers and the

Environmental Protection Agency.

Primary reasons for acceptance of the

project included the fact that the

terminal would be built within an

industrial port setting and the proposed

pipeline would follow existing,

maintained rights-of-way for almost 85

percent of its route. The Coast Guard

concluded in its preliminary Waterway

Suitability Report that the offshore

waters of Chesapeake Bay can be made

suitable for LNG marine traffic, provided

additional measures for maritime safety

and security are put in place. The

project’s pipeline, part of the Mid-Atlantic

Express Pipeline venture, would connect

with three systems in Pennsylvania:

NiSource Inc.'s Columbia Gas

Transmission Corp., Williams Cos. Inc.'s

Transcontinental Gas Pipe Line Corp.

and Spectra Energy's Texas Eastern

Transmission.

AUSTRALIAN company Santos said

it sold 40 percent of its Gladstone LNG

project to Malaysia’s Petronas for up to

US$2.5 billion after a tender process.

Petronas will make an initial cash

investment of $2Bln, plus a further

payment of $500 million upon reaching a

final investment decision for a second

LNG Train for the project that plans to

make LNG from coal-seam gas. “The

agreement with Petronas establishes a

new benchmark for the value of eastern

Australian gas resources and represents

a major step towards realisation of

Santos’ Coal Seam Gas (CSG) to LNG

strategy,” Santos said. The transaction

sells a third of Santos’ CSG proven plus

probable (2P) reserves and less than 11

percent of Santos’ total 2P oil and gas

reserves. Petronas operates an LNG

complex in Bintulu, Sarawak, producing

23 million tonnes per annum from eight

LNG trains. The Malaysian company is

also a partner in the ELNG project in

Egypt and in the Dragon LNG project in

Wales. In addition its subsidiary,

Malaysian International Shipping Corp.

is the world’s largest single owner-

operator of LNG carriers. Santos is

involved in another major LNG project in

Papua New Guinea in partnership with

other companies, including ExxonMobil.

“The agreement fully aligns the interests

of both companies across all strategic

elements of the value chain from

resources to plant development and

operation, and LNG marketing,” the

statement added. The Petronas-Santos

deal follows a $12Bln takeover bid by

LNG player BG Group of the UK for

Australia’s Origin Energy, a large coal-

seam gas resource owner. BG is also

involved in a rival coal-seam gas project,

also centred on the Australian port of

Gladstone in northern Queensland. The

Santos Gladstone project has achieved a

number of important advances during

2008, including the start of dual pre-

front-end engineering and design studies

conducted by LNG engineering

contractors Foster Wheeler and Bechtel

of the US, and the lodging of

environmental applications.

BG GROUP, the leading Atlantic

Basin LNG operator, said it signed an

agreement with Samsung Heavy

Industries of South Korea for the

delivery of two dual-fuel, diesel-electric

LNG carriers. The BG LNG shipping

fleet currently consists of more than 20

vessels that are comprised of owned and

chartered ships. The new ships will each

have a cargo capacity of 170,000 cubic

metres and are scheduled to be delivered

in 2010, BG said. “These two new vessels

are sister ships to the vessels BG ordered

from Samsung in 2006,” said Martin

Houston, BG Vice President for Global

LNG. “Their addition to the BG fleet will

further enhance performance and

provide increased flexibility in meeting

the growing demand by our customers

throughout the world for natural gas,”

Houston added. Samsung will build,

equip, launch and deliver the ships,

which will use the GTT Mark III

membrane cargo containment system.

The new ships' design specifications are

a repeat of the 170,000 cubic metres

design which is intended to provide

maximum flexibility for access into

regasification terminals around the

world while minimizing transportation

costs. Samsung has so far constructed

and delivered eight ships for BG. These

new ships are intended to replace

chartered tonnage when delivered,

BG said.

CHEVRON Corp. said VetcoGray was

awarded a five-year contract for subsea

equipment supply to the Gorgon LNG

project in Australia. VetcoGray is an

international subsidiary of GE Oil &

Gas headquartered in Florence, Italy,

and specializing in upstream subsea

equipment, drillings, completion and

production technology. Gorgon LNG, the

joint venture between operator Chevron,

Royal Dutch Shell and ExxonMobil.

plans to construct an LNG plant at

Barrow Island with three Trains each

producing 5 million tonnes per annum.

The project includes the subsea

development of the Gorgon natural gas

ABS said it was selected by Teekay

Corp. to provide technical evaluation to

the basic design concept of a floating

offshore LNG liquefaction facility the

Canadian LNG carrier company is

developing. On the opening day of the

Offshore Technology Conference (OTC) in

Houston, Texas, the American Bureau of

Shipping said the contract called for

review through to front-end engineering

and design with the award of ABS

classification to the facilities once a

suitable project has been confirmed. The

Teekay LNG/LPG liquefaction facility’s

topsides process is being designed by

Mustang Engineering of Houston, Texas

and Samsung Heavy Industries of South

Korea will design and construct the hull

for the floating LNG vessel. Initial design

concepts call for the unit to have a

combined storage capacity for LNG in

excess of 200,000 cubic metres. “The

containment system has not yet been

selected and will be greatly determined

by the site specific conditions,” said the

US classification society. “With its

approval in principle (AIP) for numerous

concepts, ABS has been at the forefront

of technical standards for gas production

at sea and novel transport technologies,”

said Mark Kremin, Vice President,

Teekay Gas Services. “The class society’s

experience with the Gaz Transport

Technigaz (GTT) Mk III system and

Ishikawajima Harima Heavy Industries’

Self-supporting, Prismatic-shape, IMO

Type-B tank (SPB) is unmatched,”

Kremin added. ABS has previously

classed the only LNG carriers to use the

SPB containment system, and also

classed the first LPG Floating Storage

and Offloading (FSO) unit newbuild, the

“Escravos”, and the first LPG Floating

Production, Storage and Offloading

(FPSO) unit newbuild, the “Sanha”, both

operating offshore Angola in southwest

Africa. ABS Project Manager John

Soland says Teekay’s project will use one

of Mustang’s proprietary LNG Smart

liquefaction solutions. Mustang’s LNG

Smart technologies are designed to

improve the commercial viability of LNG

terminals, liquefaction plants, and

floating regas and liquefaction facilities.

ABS’s evaluation of a floating gas project

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

NEWS

Newsindex

p15-30:LNG 3 06/06/2008 12:29 Page 2

fields, located about 130 kilometers off

the north-west coast of Western

Australia. “We're extremely pleased that

Chevron has selectedour technology,

which has been proven

in LNG applications

worldwide, for this major

Australian development,”

said Dave Tucker, Chief

Operating Officer of

VetcoGray. The companies

didn’t disclose the value of

the contract. The scope

of VetcoGray's contract

includes the supply

of manifolds, pipeline

termination structures,

pipeline end terminations,

trees with subsea control

modules, wellheads,

production control systems,

system integration testing,

installation and operations

support. Last year a

decision was made to

pursue a scope of three

Trains instead of two to

help improve the project

economics and address

rising industry cost

pressures. Under the

latest contract, Vetcogray’s

project and engineering

management will be based

in Western Australia.

Subsea structures and

equipment are highly

specialized and much

will be sourced from

various international

Vetcogray locations

including Singapore, the

US, the UK and Norway,

Chevron said. The Gorgon

project said it had also

started listing local

supply opportunities for

downstream procurement

on the Industry Capability

Network WA’s (ICNWA)

ProjectConnect web site.

The project said it was

committed to providing

full, fair and reasonable

opportunity for Australian

industry to supply goods

and services and is

working hard to ensure

that local content

opportunities for local

contractors are realized.

The Kellogg Joint Venture

(KJV) is the downstream

LNG journal • June 2008 • 17

NEWS

Associates. The downstream component

of the project includes the front-end

engineering and design for the project’s

gas processing and export facilities on

Barrow Island. The Gorgon project is

utilizing the vendor identification

services of the Industry Capability

Network of Western Australia to provide

contractor for Gorgon and is an

unincorporated partnership between

KBR of the US, JGC Corp. of Japan, and

Clough Projects Australia and Hatch

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qualified information on Australian

suppliers. Certain structures may be

fabricated in Australia where

practicable, Chevron added. “We look to

maximize Australian opportunities and

hope to see Australian industry

participate and grow its ability to

engage in the subsea development area,”

said Chevron’s Gorgon General Manager

Colin Beckett. The environmental

assessment process for the expanded

Gorgon LNG scope started in February

2008 when the revision to the already

approved two 5 MTPA Trains was

formally submitted to the Western

Australian Environmental Protection

Authority. The EPA’s decision – which

was advertised in March and received no

objections – set the level of assessment

at Public Environmental Review (PER)

with an eight-week public review period.

Beckett said the project team would

continue to work with the state and

Australian governments and other

stakeholders as the expanded scope

progressed through the approval

process.

CHIYODA Corp., France’s Technip and

Fluor Corp. of the US said they won

contracts from Australia’s Woodside

Energy to carry out studies covering the

Browse LNG and Pluto LNG projects.

The three companies announced that

their Australian joint venture, known as

TCF, will carry out an onshore plant

development study, as part of the

selection process of a design concept for

the Browse LNG project, located 425

kilometers from Broome, Western

Australia. The three companies will also

prepare the “basis of design” for the

proposed second processing Train for the

Pluto LNG project, located in the Burrup

Peninsula of Australia. These two

separate studies are scheduled for

completion in the second half of 2008, the

companies said. Technip and Chiyoda are

regular LNG liquefaction project

partners and are the main contractors in

Qatar, the world’s largest LNG producer.

The French-Japanese partnership is

building LNG Trains each with a

capacity of 7.8 million tonnes per annum.

Woodside has helped turn Australia into

one of the world’s main LNG producers.

The company is aiming between now and

the end of 2010 for final investment

decisions for an expansion of Pluto LNG,

and the development of the Browse and

Sunrise LNG projects. At the end of

2010, Australia will have seven LNG

Trains in operation, six of them operated

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

NEWS

by Woodside and the other at Darwin

LNG, where US major ConocoPhillips is

the operator. Excelerate Energy, the

offshore and dockside LNG terminal

developer, has set up an import facility

for Argentina at the port city of Bahía

Blanca, about 400 miles south of

Buenos Aires.

EXCELERATE, which is 50 percent

owned by Germany’s RWE, said the

Bahía Blanca GasPort is Excelerate's

fourth operational LNG facility and

second dockside terminal using LNG

regasification vessels. Excelerate’s

vessels are equipped with both an

onboard regasification system and a

normal LNG discharge capability,

enabling them to offload at conventional

LNG terminals, their own facilities or in

ship-to-ship operations. The Argentine

facility will allow the delivery of up to 400

million cubic feet of natural gas per day

to Argentina's market. The facility has

the capacity to import up to three LNG

cargoes per month. Excelerate’s GasPort

technology involves a dedicated jetty and

a converted LNG carrier that regasifies

the cargo and feeds it directly into the

natural gas network. The company's first

GasPort at Teesside in the UK was

commissioned in February, 2007, though

like all of Excelerate’s facilities it has

suffered from the global shortage of

surplus LNG cargoes. “This facility

marks yet another milestone for

Excelerate Energy and further

demonstrates how the unique ability of

our onboard regasification and GasPort

technology can quickly and cost-

effectively deliver LNG supplies and

connect markets globally,” said Rob

Bryngelson, Excelerate’s Chief Executive.

The commissioning cargo for the Bahia

Blanca GasPort was sold to the Spanish-

Argentine energy company Repsol YPF

by Excelerate and loaded onto the carrier

the “Excelsior” by ship-to-ship transfer on

May 4. This cargo was delivered from

another of Excelerate's regasification

vessels the “Excellence” and marked the

fifth transfer of LNG between two ships

for commercial purposes. Excelerate has

been the pioneer in STS transfer and

continues to use this process to provide

additional flexibility for scheduling and

fleet use. Meanwhile, the Excelerate

vessel “Excellence” took part in the first

LNG delivery to the company’s Northeast

Gateway, located 18 miles east of Boston

in Massachusetts Bay. The vessel fed its

cargo into the existing HubLine natural

gas pipeline system operated by Spectra

Energy. “This delivery is a milestone in

efforts to bring a new, safe, clean,

affordable energy source to the New

England region in record time,” said

Bryngelson. “During the course of this

project it became extremely clear that our

ship-board regasification technology is

the quickest, least expensive and most

environmentally responsible way to bring

new natural gas supplies to markets,” he

added. Excelerate and Spectra Energy,

both based in Houston, Texas, teamed up

to extend a 16-mile, 24-inch pipeline

lateral from Spectra Energy's HubLine to

the offshore facility. The system is

capable of supplying up to 20 percent of

New England's natural gas demand,

Excelerate said. Aside from the

Northeast Gateway, Excelerate also

operates the Gulf Gateway in the Gulf of

Mexico, about 116 miles south of

Louisiana.

EXXONMOBIL Corp., operator of the

$10-billion PNG LNG project, said it

signed a formal joint venture agreement

with the Papua New Guinea state,

opening the way for the venture to enter

the engineering phase. The joint venture

deal and an accompanying gas

agreement establish the fiscal regime

and legal framework by which the LNG

project will be regulated throughout its

lifetime. It also sets the terms and

mechanism for state equity

participation, ExxonMobil said in a

statement. Following the signing

ceremony, the US major said it would

immediately enter the front-end

engineering and design stage. The PNG

LNG project is an integrated

development which includes all

components including the gas processing

facilities, pipelines, and LNG plant.

ExxonMobil’s current partners include

Australian companies Santos and Oil

Search, as well as Japan’s Nippon Oil.

However, shareholding levels will change

when the PNG government’s nominees

join as equity participants at a later

date. The agreement was signed on

behalf of the State of Papua New Guinea

by the Governor General, Sir Paulias

Matane, and Minister for Petroleum and

Energy William Duma. The FEED team

will comprise personnel from

ExxonMobil, the joint venture companies

and the contractors based in PNG,

Australia, the US and Japan.

“ExxonMobil is pleased to have the Gas

Agreement executed and to move this

project to the next stage of development,”

said Peter Graham, Project Executive,

ExxonMobil Development Co. “During

the FEED stage we will also pursue LNG

sales agreements, secure the necessary

permits and licenses, and undertake the

financial planning necessary for a final

investment decision,” Graham added.

FRANCE’S Total said it made a

significant natural gas discovery in the

Maharaja Lela-Jamalulalam gas field

that already supplies the Brunei LNG

plant. The French company said the

discovery was made about 50 kilometres

offshore in the MLJ2-06 well. Total is a

shareholder along with Royal Dutch

Shell and the Brunei authorities. With a

final depth of 5,850 metres, the well is

the deepest ever drilled in Brunei in

a high pressure/high temperature

reservoir, Total said. “Other new gas

compartments in the Maharaja Lela-

Jamalulalam field have been detected

and further appraisal work is necessary

to evaluate them,” Total said in a

statement. Total, which has been present

in Brunei since 1986, said the new well

should come onstream before the end of

2008. In addition, Total holds a 60

percent interest in Brunei’s exploration

block J, situated deep offshore, for which

a production-sharing agreement had

been signed in March 2003. Exploration

activities on this block have been

suspended since May 2003, awaiting the

resolution of a border dispute with

Malaysia. Total’s production in the Asia-

Far East region amounts to 11 percent of

the group’s production, though its assets

are mainly located in Indonesia, another

LNG producer.

GASOL, the venture company formed

to find LNG opportunities off West

Africa, has exercised an option to acquire

all the shares in African LNG, a project

company in which it previously held a

minority stake. The deal follows the

signing last month by Gasol of a heads of

agreement with Canadian LNG carrier

owner Teekay Corp. to collaborate on

possible LNG projects in West and

Central Africa. The companies said they

would cooperate in African operations by

seeking to develop LNG capacity using

floating liquefaction technologies and

would invest in LNG vessels and

regasification terminals, including

Floating Storage and Regasification

Units. Gasol, whose shares are listed on

London’s Alternative Investment

Market, said the all-share transaction to

acquire African LNG would involve the

issuing of 623 million Gasol shares, or

p15-30:LNG 3 06/06/2008 12:29 Page 4

LNG journal • June 2008 • 19

about 75 percent of the enlarged

company's share capital. The deal

constitutes a reverse takeover. Theo

Oerlemans, the current chairman of

African LNG, will join the Gasol board as

non-executive chairman. “Completion of

this significant transaction will position

Gasol to become the premier

independent LNG player in the Gulf of

Guinea,” said Gasol Chief Executive

Soumo Bose. “It will further strengthen

Gasol’s Board and management team

and its relationships in the region, and

bring to Gasol a number of LNG business

development opportunities in the Gulf of

Guinea.” Bose added. Gasol was founded

in 2005 and has the mission of becoming

an integrated LNG company in West and

Central Africa through acquisitions,

investments and alliances.

GAZ DE FRANCE and Hoegh LNG

of Norway said they agreed to set up a

floating LNG import facility offshore the

Adriatic coast of Italy. The floating

storage and regasification unit will be

owned by GdF and operated by Hoegh.

GdF is currently completing its merger

process with Franco-Belgian peer Suez

that will give the enlarged companies a

powerful position in the Atlantic Basin in

terms of trading, LNG offtake and

regasification capacity in Europe and the

US. However, the Italian facility will fill a

gap for the pair in Italy. The facility is the

third offshore import terminal planned

for the Italian coast. One of them, also

offshore the Adriatic, is owned by

ExxonMobil and Qatar Petroleum. Hoegh

operates five LNG carriers and has two

shuttle and regasification vessels (SRVs)

on order. Hoegh is also developing two

offshore terminals based on the SRV

technology in Florida and the UK. GdF

and Hoegh said their Adriatic LNG

project would be called Triton LNG and

located 30 kilometres offshore. The LNG

storage capacity of the FSRU would be

about 170,000 cubic metres and the

baseload regasification capacity 5 billion

cubic metres. “The technologies involved

in the FSRU-vessel and in the ship-to-

ship LNG transfer will be selected to

gather the safest and most cost efficient

and environment-friendly solutions,” the

companies said. “The studies related to

the permitting and development of the

Triton LNG project are already well

advanced. The final investment decision

should be reached by the end of 2009,

with first LNG deliveries before the end

of 2012,” they said. GdF Chief Operating

Officer Jean-Marie Dauger, who will run

the new LNG division of the merged

GdF-Suez, said: “The Triton project

serves a double purpose: allowing Gaz de

France to be a player in LNG

development and to reinforce its presence

in Italy, where we have ambitions for a

long-term presence, contributing to the

energy supply of the country.”

IMPORTS of LNG by Asian countries

and North America soared in 2007 but

Europe’s LNG imports dropped,

according to the latest statistics from

Paris-based Cedigaz. LNG pursued its

“sustained and buoyant expansion

worldwide” with global LNG trade rising

by 7.3 percent to about 172 million

tonnes, a rise of 12.5 million tonnes. In

2007, LNG demand in the Asia Pacific

reached just over 112 million tonnes, a

rise of almost 10 percent. Japan was the

biggest importer with 66.8 million

tonnes and South Korea second highest

with 25.6 million tonnes. In Europe,

Spain was the largest importer with

NEWS

p15-30:LNG 3 06/06/2008 12:29 Page 5

18.9 million tonnes, almost twice as

much as France’s 9.7 million tonnes.

Overall, Europe imported 41 million

tonnes, about 4 tonnes less than the

previous year. The US posted a 32

percent rise in imports in 2007 to 16.2

million and Mexico imported 2 million

tonnes. The year 2007 was marked by

the start-up of two new liquefaction

plants in Norway and Equatorial

Guinea, opening new LNG routes,

Cedigaz said. However, due to technical

problems and shut down periods, these

plants could only produce limited

quantities of LNG last year, the Cedigaz

survey said. LNG's share of global

natural gas trading rose to 25 percent in

2007 from 23.7 percent the previous

year, Cedigaz added. The natural gas

industry data compiler and seller said

that overall international gas trade

including pipeline supplies increased 2

percent to 905 billion cubic metres last

year, making up 31 percent of the

world's marketed production. According

to the Cedigaz figures, global natural

gas trade by pipeline grew a modest 0.4

percent to 679 Bcm in 2007. Larger

intra-regional trade in North America,

Asia and the Middle East offset the drop

in Russian and Algerian exports to the

European continent and pipeline flows

in Latin America due to Argentina's

exports cuts. Therefore, LNG trade

accounted for the bulk of the growing

global trade. LNG supplies represented

7.7 percent of worldwide gas supply in

2007, compared to 7.3 percent the

previous year.

LNG IMPEL of Canada announced

development plans for a venture called

Southern Cross LNG, which would be an

open-access liquefaction plant for coal-

seam gas producers in the Australian

state of Queensland. The project is the

third announced for the same area

around the Port of Gladstone to produce

LNG from Australian coal-seam gas. Of

the other two projects, one involves

Australian oil and gas company Santos

and a second involves BG Group of the

UK, an experienced LNG player. LNG

Impel, a subsidiary of Calgary-based

Galveston LNG, said its Southern Cross

venture would include liquefaction

processing, two 160,000 cubic metres

storage tanks and marine loading

capabilities. The facility would be built in

modules to allow for expansion, and the

site has already been scoped for three

liquefaction Trains, Impel said in a

statement. Each individual Train would

have a capacity range of 700,000 tonnes

to 1.3 million tonnes per annum. The

Southern Cross Train 1 is scheduled for

operation in 2013, with a rolling

expansion program designed to fit supply

availability, the company said. A

Southern Cross pipeline will be a 16-24-

inch open access gas transportation route

of about 400 kilometres, which will be

constructed to connect feed-gas to the

Southern Cross plant. “By providing an

open-access service, which to date has not

been available in Australia, Southern

Cross LNG will appeal to producers of

varying sizes,” the company said. Impel

believes that this model will also allow

junior producers access to the

international gas markets and provide

them with the opportunity to realize an

international netback price for their gas

reserves,” Impel added. “For those

producers not wishing to be exposed to an

international pricing formula or netback

arrangement, Impel will purchase gas at

a market-based price on the pipeline

system or at the inlet to the facility,”` it

said. Southern Cross will also offer

processing services for those producers

wishing to market their own gas as LNG

if they have sufficient quantities to do so.

Impel said the Gladstone Ports Corp. had

allocated a site located on Curtis Island

to Impel for the Southern Cross LNG

project after a 12-month review by Impel

for a preferred site. The preliminary

feasibility analysis of the site was

undertaken by CDS Research, LNG

engineering specialists based in

Vancouver, Canada. Impel said it had

also entered into a preliminary

agreement with CB&I Lummus for the

use of their liquefaction technology and

engineering services.

KUWAIT National Petroleum Co. said

it was in talks with Qatar Petroleum to

secure LNG for an import facility

expected to be set by Excelerate Energy

of the US using a regasification vessel.

KNPC said it signed an agreement last

month with Excelerate to qualify and

prepare the South Pier near the Mina Al

Ahmadi oil refinery so as to support LNG

import operations. Excelerate has yet to

make a statement, suggesting aspects of

the project have to be finalized. Despite

the Middle East being the hub of energy

production, Kuwait and several other oil

and gas producers are short of natural

gas for power generation during the peak

summer demand period and Kuwait

often suffers power blackouts. According

to KNPC, a $150 million contract was

signed last month by KNPC Deputy

Chairman Asaad Al-Saad and Edward

Scott, Excelerate’s Vice President for

Development. KNPC said the country

plans to begin LNG imports in about a

year. Dubai in the United Arab Emirates

is also planning an LNG import facility

using a berthed regasification vessel. The

talks with the Qataris could lead to a

solution whereby Kuwait would receive

seasonal imports of spot cargoes to fill its

power station shortfalls of natural gas.

The project is scheduled to be complete

by April 2009, KNPC said. Kuwait is the

second Gulf state to move forward on an

LNG import programme, The Dubai

authorities in April signed an LNG

supply agreement for around 15 years

with Qatargas and Royal Dutch Shell to

receive supplies in the United Arab

Emirates. Dubai is planning a floating

regasification and storage unit charter

from Golar LNG for $450M. The LNG

will be supplied from 2010 to an FSRU, a

converted LNG carrier, the Dubai

emirate is planning to site at Jebel

Ali port.

ORIGIN Energy of Australia rejected a

revised US$13 billion takeover bid from

LNG player BG Group, saying another

deal between Petronas and Santos had

boosted the value of coal-seam methane

assets as feed gas for LNG. Origin,

Australia's largest coal-seam gas

producer, also more than doubled the

value of its coal-seam gas reserves to over

US$15Bln as it seeks a higher offer from

the UK-based company. Another

transaction announced on May 29 under

which Malaysia’s Petronas agreed to pay

Australia’s Santos $2.5Bln for a 40

percent stake in the Gladstone LNG

project that will use coal-seam gas

influenced origin’s decision, the company

said. “The Santos announcement

establishes a new and higher benchmark

for the value of CSG and, along with the

proposed BG LNG project, demonstrates

confidence in the use of CSG for LNG

production,” Origin said in its statement

rejecting BG’s offer. “It is particularly

relevant to the valuation of Origin’s CSG

interests, which includes acreage covered

by and adjacent to the acreage being

acquired by Petronas,” Origin said. Origin

added that it had also increased its

certified reserves since the original BG

offer. “Origin commissioned Netherland,

Sewell & Associates Inc. to review and

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

NEWS

September2nd Annual LNG Tech Global Summit

2007

Rotterdam, Netherlands

10th - 12th September 2007

www.lngsummit.com

2nd Asia LNG Summit 2007

Beijing, China

20-21 September 2007

www.LNG-summit.com

The 7th Annual Italian Energy Summit

Milan, Italy

26th - 28th September 2007

wing.yan.lee@informa.com

China Power Markets & Project

Conference 2007

Beijing, China

27-28 September 2007

www.inc-global.com

OctoberThe 2nd Annual Global LNG

Infrastructure Summit

NH Mexico City, Mexico

4-5 October 2007

www.cityandfinancial.com/lng2

Autumn Launch, The Energy Institute

16 October 2007

London, UK

2008 international LNG Projects andTechnology Week27-31st of October 2008Shanghai Chinawww.lngweek.org

Course: "Fundamentals of BaseloadLNG: Markets, Technology, Economics"29 October - 2 November, 2007Houston, USAwww.gastechnology.org/classroom.

November20th World Energy CongressRome, Italy11- 15 November 2007www.rome2007.it. Fair and Congress on Alternative,Renewable, Clean and Co-generatedEnergySão Paulo – SP – Brazil27-29 November 2007www.latinevent.com.br

DecemberEight Annual World LNG SummitRome, Italy3- 5 December 2007LNG/GTL Tech Asia Summit 2007Kuala Lumpur, Malaysia4-6 December 2007www.safan.com/conferences/ phconf.htm

Diary of events

p15-30:LNG 3 06/06/2008 12:29 Page 6

certify its reserves and resources in its

CSG tenements. This report shows, as at

15 May 2008, significant expansion in the

CSG resource base available to Origin,”

the company added. Origin

received its first unsolicited

bid from BG on April 29

when the UK company

offered A$14.70 per share.

The Australian company

said in its statement

rejecting BG’s approach

that since the original offer,

the bid from BG had been

increased to A$15.50 per

share, but that was still not

enough. “The board of

Origin has given careful

consideration to all of the

relevant information

available to it, particularly

the substantial increase in

the company’s CSG

resource base and the

demonstrably higher value

now placed on CSG

resources,” said Origin

Chairman Kevin McCann.

“The board has decided that

the revised proposal does

not adequately reflect the

greater value that will be

available to shareholders by

not accepting this proposal,”

McCann added.

OTC, the Offshore

Technology Conference in

Houston, concluded after

four days with more than

75,000 paying energy

industry professionals

attending to hear around

300 technical presentations,

and with a bigger focus on

US LNG and offshore LNG

technology. The organizers

said attendance was up 11

percent on last year to

reach a 26-year high at the

Reliant Park venue in the

Texan city, which is the

capital of the US energy

industry and where all the

main international

companies have offices. The

exhibition area included

2,500 companies from 35

countries, with stands

covering an area equivalent

to 13 American football

fields. “OTC is

where offshore energy

LNG journal • June 2008 • 21

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resources in harsher and more extreme

conditions,” Vardeman added. The LNG

presentations at the conference included

US prospects of boosting volumes for its

professionals come to learn about

innovative approaches to overcoming

technical challenges as we drill in deeper

waters,” said Don Vardeman, OTC

Chairman. “Technology will be crucial to

delivering affordable and sustainable

energy for the future. OTC offers the

chance to share knowledge about getting

p15-30:LNG 3 06/06/2008 12:30 Page 7

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

NEWS

growing import terminal network,

LNG facility expansions, LNG transfer

technology for offshore liquefaction

plants and terminals, and innovations

on offshore liquefaction platforms and

equipment. Next year’s event takes

place at the same venue starting on

May 5, 2009.

PROJECT TENDER changes could

break the logjam in the industry that

has seen contract backlogs double

among the top 10 engineering,

procurement and construction

companies in the past five years. The

call came from a senior executive at the

annual Offshore Technology Conference

in Houston, Texas, after a

series of LNG liquefaction

project and cost overruns

caused by shortages of

skilled personnel and

materials. Recent large

LNG projects have suffered

serious cost overruns as

the prices of key

commodities such as

stainless steel have tripled

over the last three years

and the costs of equipment

such as compressors have

almost doubled. “The

strategy of competitive bids

at each stage of a project in

today’s environment can

result in qualified bidders

declining to participate,

risk premiums being added

to pricing and uncertain

access to qualified project

teams,” said Tom Phalen,

Vice President at US EPC

company Fluor Corp. “By

committing early in the

project development to an

EPC contractor, and by

working with them to

develop a viable strategy,

an LNG facility owner can

tie up valuable resources

for the project and lower

risk,” Phalen added. “The

schedule and risk benefits

of this approach can

typically outweigh any cost

advantage relative to a

traditional competitive bid

approach,” he said. In

addition, an LNG facility

owner can broaden its

access to key resources by

using teams of contractors

on its projects for work

other than the liquefaction.

The liquefaction portion of

any LNG facility project

typically represents 34

percent to 38 percent of the

total project, so the

developer can use a skilled

liquefaction portion

contractor and teams from

various other contractors

for the rest of the work,

Phalen said. Most of the

recent LNG liquefaction

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p15-30:LNG 3 06/06/2008 12:37 Page 8

LNG journal • June 2008 • 23

NEWS

Chief Operating Officer for Shell

Development (Australia) Pty Ltd. “Shell

has global gas marketing and financial

strengths coupled with leading research

projects have been executed by LNG

industry leaders Bechtel of the US, the

joint venture partners Chiyoda of Japan

and Technip of France, and the joint

venture team of KBR and

JGC Corp. of Japan.

SHELL has announced a

deal to enter the coal-seam

LNG business after it

signed an agreement with

Arrow Energy of Australia

to jointly develop projects

in Australia, China,

Indonesia, Vietnam and

India. The alliance with

Arrow will boost Shell's

existing strategic positions

in potential coal seam gas

areas, the companies said.

Arrow has significant CSG

production facilities in

Queensland, Australia,

where it is the largest CSG

acreage holder. It has four

producing projects in

Queensland, and supplies

gas for industrial users

such as power stations.

The memorandum of

understanding calls for

Shell to acquire a 30

percent interest in Arrow's

CSG acreage in

Queensland, as well as a 10

percent stake in Arrow

International - a wholly

owned subsidiary of Arrow

Energy Ltd, which holds

Arrow's international

interests in CSG. The

agreement also gives Shell

a five-year option to

acquire up to 50 percent

of individual Arrow

International projects,

which includes activities in

China, Shell said in a

statement. Under the deal

Shell would also acquire

the right to negotiate an

agreement to purchase any

LNG that may potentially

be produced from the CSG

operations. “Shell and

Arrow have also agreed to

undertake further research

and development in this

important and growing

area of gas supply,” Shell

said. “Shell will also assign

at least five personnel to

work at Arrow's operations.

The total value of the agreement is

expected to be up to US$0.7 billion.

Completion of a definitive agreement is

anticipated in the near term,” the

statement added. “This proposed

alliance between Shell and Arrow would

combine the complementary strengths of

our two companies,” said Chris Gunner,

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p15-30:LNG 3 06/06/2008 12:32 Page 9

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

NEWS

capabilities. Arrow has proven CSG

expertise, and extensive Australian and

international CSG acreage positions.

"We look forward to working with Arrow

and creating an alliance that should

become a significant force in the

development of CSG resources,”

Gunner said.

SHELL ship management signed an

agreement in Washington on April 30

with the American Maritime Officers

Union for AMO deck and engine officers

to be recruited for Shell-managed LNG

carriers. The signing of the

memorandum of understanding will take

place at the US Department of

Transportation, with Richard Mellor,

General Manager for Shell Ship

Management, signing on behalf of Shell

and Tom Bethel, National President of

the AMO, signing for the US side. Shell

announced in February that the

recruitment process had already begun

as the company said it was pleased to

link up with “an exceptional skill pool,

particularly for LNG vessels.” The

growing demand for LNG has led to

many import projects being put forward,

including Shell’s US venture,

Broadwater LNG, a $700 million offshore

project to be developed by Shell and

TransCanada Corp. in Long Island

Sound, off New York State. The focus of

local opposition to such operations has

been security. Other LNG companies

with US import and marketing

businesses, such as Suez North America,

have announced plans to increase the

number of US nationals crewing carriers

calling at US ports to help alleviate the

concerns of citizens and ease pressures

on the planning process. Shell currently

employs more than 500 marine officers

with LNG experience around the world,

and is looking to further expand the

presence of US mariners as it takes

delivery of new ships in the next two

years. Shell has LNG carrier operations

delivering from nations such as Qatar,

Brunei, Malaysia, Nigeria and Australia

and helps train officers from those

countries.

US buyers will face a widening gap in

the next few years between natural gas

supply and demand, and LNG will have

to fill a large portion of this demand at

very high prices, the annual Offshore

Technology Conference in Houston was

told. Addressing an LNG session at the

OTC, McKinsey & Co consultant Mike

Juden said that projections suggested

that by 2015 the US natural gas

shortfall would amount to 22 billion

cubic feet per day. In 2007, US natural

gas demand was 73 billion cubic feet per

day and supply was 70 Bcf/d. By 2015

demand is expected to reach 92 Bcf/d

and supply will still be around the 70

Bcf/d level. One billion cubic feet per day

of natural gas is equivalent to 7 million

tonnes per annum of LNG. “LNG has got

to fill a significant portion of this gap in

the US and Canada,” said Juden. “We

shall have a huge problem” unless the

natural gas gap can be filled. The

McKinsey executive said that LNG was

one of the main hopes for the energy

market as expansion of the nuclear

power infrastructure in the US “was still

10 years out.” He said that according to

all the facts, alternative energy such as

wind-power would never provide enough

energy to reduce the country’s reliance

on natural gas and LNG. With global

LNG production in 2007 of less than 200

million tonnes per annum and

worldwide regasification capacity at

more than 400 million tonnes, there was

a clear deficiency in supply. According to

Juden, the US would have to pay

premium prices for LNG to match the

highest feed fuel prices for power plants,

such as distillate, which would mean

paying equivalent prices of up to $17 per

million British thermal units. That

compares with current US natural gas

prices of around $10 to $11 per MMBtu.

These prices are equivalent to those paid

by Japanese buyers for spot cargoes over

the past six months. At the same time,

buyers for the US market would be

unable to compete even with European

buyers for most of the year unless given

the advantage of a mild European

winter season, delegates were told. With

the US now even longer on

regasification capacity after the opening

of two new terminals at Sabine Pass,

Louisiana, and Freeport, Texas, the US

gas business is expected to find life

difficult in the LNG world in the years

ahead. Countries such as Russia, Qatar

and Nigeria have the potential to boost

global LNG supplies. However, the

conference heard that Russia’s LNG

development future was far from

certain, Qatar was likely to have a

moratorium on new projects post-2010

and Nigeria was expected to continue to

be afflicted by political unrest. Other

leading producers such as Indonesia and

Malaysia would be unlikely to provide a

solution because of depleting or

stagnating natural gas supplies and

under investment. “It will be difficult to

attract LNG to North America, period,”

said Juden. “We shall have a huge

problem in the short to medium term.”

He said McKinsey wasn't making a

forecast, just relating the facts as they

are now.

WOODSIDE Petroleum said new

LNG projects it’s working on contain

gross proved and probable reserves and

contingent resources of about 50 trillion

cubic feet of dry gas. Speaking at the

company’s annual meeting in the

Western Australian city of Perth,

Woodside Chairman Michael Chaney

said because of the available long-term

volumes customers in Asia will be willing

to pay “prices for LNG which are close to

oil price equivalent”.“In the North West

Shelf Venture we have a large, sound and

profitable legacy asset,” said Chaney.

“Our Pluto LNG Project will begin

deliveries in just 32 months and we are

aiming to begin construction of another

two developments - Browse and Sunrise

- within the next few years.” However,

Woodside Chief Executive Don Voelte

told shareholders the company’s

exploration record was not as he had

hoped, though it was still well prepared

for the future. “I make no secret of the

fact we would have liked to have found

more hydrocarbons in 2007,” said Voelte.

“The disappointment with our

exploration success last year remains

tempered, however, by the knowledge

that our proved plus probable reserves to

production ratio remains extremely high

at 25 years, and more than 60 years

when contingent resources are included.”

Woodside was aiming between now and

the end of 2010 for final investment

decisions for an expansion of Pluto LNG,

and the development of the Browse and

Sunrise LNG projects. At the end of 2010

Australia will have seven LNG Trains in

operation, six of them operated by

Woodside and the other at Darwin LNG

by ConocoPhillips. When Woodside

announced in August 2005 that we

intended to build an LNG project based

on our Pluto discovery, made just four

months earlier, many in the industry

questioned whether we could or would do

that,” said Voelte. Less than three years

later, Voelte said the modules for the first

LNG Train at Pluto were under

construction in Thailand, the platform

was being assembled in China, the

topsides were being put together in

Malaysia, and at the plant site at

Karratha the walls of the LNG storage

tanks were going up. “We have set our

goals high in relation to the Browse and

Sunrise developments, and an expansion

at Pluto,” said Voelte.

WOODSIDE conducted site visits last

month for investors and energy

executives to its North West Shelf LNG

operation and its Pluto LNG project in

Northwest Australia and said

engineering plans for a Train 2 for Pluto

would be completed this year. The

investors were also shown that Train V

of the NWS LNG expansion was almost

complete and would come on stream as

scheduled in the fourth quarter of 2008.

The fifth train at the NWS complex at

Karratha would boost LNG production

to 16.3 million tonnes per annum. The

Train’s final cost was put at A$2.6

billion (US$2.4Bln). In addition to the

new Train, work was completed on a

second LNG loading jetty for NWS,

additional fractionation, power

generation, fuel gas and boil-off gas

facilities and offshore feed-gas projects

were being worked on. On the A$12Bln

(US$11.2Bln) Pluto LNG project,

Woodside told investors that

engineering plans for a Train 2 would be

completed by the end of 2008. However,

the Pluto LNG Train 2 final investment

decision “requires new gas either from

Woodside discoveries or other resource

owners.” Woodside said Pluto was still on

track to be the fastest LNG project in

the world from discovery in 2005 to first

gas in late 2010. Pluto’s onshore Burrup

LNG complex would establish a

foundation for future growth with at

least three Trains planned long-term for

the site. Meanwhile, another planned

Woodside project, Sunrise LNG, will be

on the agenda when Australian

Resources Minister Martin Ferguson

visits East Timor this week. The Sunrise

LNG project could become the first

major offshore LNG venture using Royal

Dutch Shell’s FLNG technology that is

currently under development. Shell is

one of the Sunrise shareholders. East

Timor has already received about

A$1.5Bln in royalties from another

Australian-based LNG project, Darwin

LNG run by ConocoPhillips that takes

gas from Bayu Undan in the Timor Sea.

An LNG project based on Shell FLNG

technology would remove potential

political delays in the Sunrise venture

as there would be no need for an onshore

LNG plant in East Timor nor in

Australia. It would also substantially

reduce costs. �

p15-30:LNG 3 06/06/2008 12:32 Page 10

LNG journal • June 2008 • 25

REGASIFICATION

There have been big developments in

offshore receiving terminal design, where

many companies are hoping new

technology can ameliorate the actual or

perceived risks of a land-based location

without introducing too many new

dangers and challenges.

Until Excelerate Energy’s Floating

Storage and Re-gasification Unit (FRSU)

opened in the Gulf of Mexico, all LNG

import terminals were land-based.

Now an FRSU has begun operations off

the Northeast coast of the US and others

are under construction in offshore

Tuscany in Italy (using a refitted LNG

carrier), Southern California (using a new,

dedicated vessel), as well as at Pecem and

Guanabara Bay offshore Brazil.

Others are planned around the world

and a limited number of key parameters

are decisive for concept selection in terms

of offshore versus onshore.

With the exception of Brazil, the main

motivation for the offshore developments

currently under construction has been

concern about safety and security.

This is in a way demonstrated by the

fact that the first offshore developments

are taking place in US and Italy where

the opposition has been particularly

focused on public safety.

Common factorAlthough the concern is slightly different

in the two countries, a massive public

opposition against onshore developments

is a common factor.

For the Brazil developments the

motivation for offshore solutions has

flavours from several parameters such as

sufficient distances to third parties,

limited site development cost and

existing gas grid in the proximity.

However, the short lead time for the

project development compared to an

onshore development has been decisive.

The short lead time is possible by

converting existing LNG Carriers to

floating re-gas facilities.

The main drivers for the offshore

developments with granted Final

Investment Decision (FID) is safety and

security for the Italian project and time

to market for the Brazilian projects.

For projects the offshore project

portfolio (with and without FID), there

are a few additional key parameters that

have been decisive for investing. In the

following these important parameters

and their interaction are discussed.

SafetyBecause LNG is poorly understood by the

general public, the industry has faced the

constant risk that public perception will

be based on fears and falsehoods. This

environment allows professional

opposition groups to present catastrophic

scenarios as if they were equally credible

with official studies.

The consequence-based permitting

process in the US unfortunately lends

credence to these fears, because it focuses

on the worst case rather than providing

the public with the full range of scenarios.

The suitability for offshore

development to address of safety and

security in the US was recently

reconfirmed by the aggressive marketing

of the Blue Ocean terminal outside New

Jersey, following massive opposition

against the Broadwater project.

Net present value While the discussion related to offshore

terminal versus onshore commonly focus

on around the cost side of the

development, the FID needs to be based

on actual return on the investment,

commonly termed “Net Present Value”

(NPV) of the investment.

Simplified the “net present value”

indicate what is todays value of the

investment, and is a function of CAPEX,

OPEX, revenues and the minimum

required return on the investment used

as the discount factor.

Most LNG projects has long time from

initiation of project costs to positive cash-

flow. In addition, high financial risks

attributed to the projects requires

relatively high discount factors. Positive

cash-flows years into the future has little

positive impact on NPV. FID for LNG

terminals are hence sensitive to CAPEX,

OPEX, Revenues (through-put),

execution risks and last but not least,

time to positive cash generation.

CapexTraditionally, CAPEX for onshore

development has been perceived as

higher than for offshore developments.

Currently it is challenging to directly

compare the development cost

between projects, as the industry

has been exposed to a cost

increase in the range of 80%

over the latest three years.

Further, CAPEX is a

function of the terminal re-

gasification and storage

capacity as well as well as

cost related to site specific

construction needs.

There are some recent

examples that the CAPEX is not

necessarily higher for an offshore

development. The GATE terminal (9

BCM) in Rotterdam has announced a

budget of 800 million euros, while the

Blue Ocean project (12 BCM) outside

New Jersey has indicated a development

cost of $1Bln.

When comparing these figures one

needs to bear in mind that the Blue

Ocean project is at much earlier

development stage. From experience,

without any project specific knowledge or

reference, the probability for a cost

increase is higher for less developed

projects.

Research carried out by DNV indicate

that the CAPEX for an offshore

development could be in the range of 10–

40%, relative to an onshore development

of similar capacities. One important

parameter for the CAPEX is the required

pipeline distances, both cryogenic and

natural gas pipeline.

Required pipeline distance may alter

the project CAPEX, in terms of offshore

versus onshore. In relation to cryogenic

pipeline lengths, the environmental

properties of available areas and the jetty

landfall are decisive, while the length of

the natural gas pipeline is a function of

the distance to the existing gas grid.

Operating costThe operating cost for a import terminal

is influenced by a number factors, the

main one being energy consumption for

re-gasification, maintenance activities

and labour cost.

The energy cost is mainly affected by

the type of vaporisers that are selected.

Vaporisers based on gas burners, as well

as seawater assisted vaporisers are

available for both offshore and onshore

developments.

The potential for utilizing seawater is

more linked to the local sea temperature

and potential environmental restriction

on release of cool water, than the concept

selection.

On the maintenance side it is assessed

that the volume in terms of maintenance

hours for the terminal will be higher for

an offshore terminal. However, it is not

assessed to be essentially different for an

onshore terminal.

An FSRU that holds maritime

certificates will need a renewal survey

with dry docking every fifth year. The

FSRU can not receive or deliver LNG in

such periods and will also require time

for cool down procedures to prepared the

facility for a new 5 year period of

operation.

Certiifcation through an offshore

regime would increase CAPEX but make

it possible to replace the renewal survey

with a continuous survey program

avoiding business interruption. This

decision can differentiate NPV figures

significantly.

The labour cost is again more linked to

the local labour marked than the concept

selection, although there could be some

implications by the need for a maritime

crew on and FSRU.

From the above discussion it is

concluded that although optimisation is

very important parameter in concept

selection, it has not been decisive for the

onshore versus offshore decision

Offshore LNG develops too for newregasification technologyHans Kristian Danielsen and Goran Andreassen

The operating cost for a import terminal isinfluenced by [mainly]energy consumption for

re-gasification,maintenance activities

and labour cost.

p15-30:LNG 3 06/06/2008 12:42 Page 11

REGASIFICATION

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

ThroughputIn any LNG supply chain there are a

variety of cooperating and competing

stakeholders.

The complexity of the supply chains

will increase when different gas

importers are using the same terminals.

In this picture an evolving and

increasingly interesting LNG spot

market are bringing risks and

opportunities to the various stakeholders.

On the positive side it will be a more

flexible market with increased

possibilities for catching up delays.

The flipside is less predictable carrier

arrival frequencies at import terminals.

The industry is in a way still young and

limited causing many players in the LNG

industry to take high risk investment

positions without a thorough under-

standing of the risks and opportunities.

There are examples of terminal

operators overselling capacity and import

companies committing to downstream

sales agreements that with higher

probability of failure than success.

To build the necessary decision basis

for investments in the LNG supply chain,

simulation models are extremely

valuable. Advanced simulation software

can be used to forecast the performance

of complex supply chains and user

agreements.

When assessing yearly “gas through

put” and the terminals quality in terms

of availability, the key parameters are

significantly affected by the terminal

concept selection. In the two next sub-

sections, “through put” related key

parameters influencing the selection of

an offshore or onshore LNG import

terminal are discussed.

OnshoreFor onshore developments the terminal

capacity is commonly defined by the

storage and re-gasification capacity.

However, the actual capacity is often

restricted by operational constraints such

as restricted berth availability due

arrival slots. Such slots are governed by

traffic restrictions, tidal restrictions.

For multi-user terminals, lack of

berthing rights at the desired time of

arrival may become an issue. For these

shared terminals, storage capacity has

also proven a potential restriction on

utilizing the maximum theoretical

capacity of the terminal.

For offshore terminals the sea state

and the terminals ability to receive

cargos at given wave heights may be the

greatest challenge.

It is interesting to notice that most

discussions are focused on the wave

heights, while the parameter with most

impact on side by side unloading

operations is the wave period.

Depending on design, a mooring

arrangement may experience excessive

loads in low sea states if the wave period

is co-inciding with the roll period of the

LNG carrier.

Storage capacity is a design issue with

no particular limit. Extensive

engineering and design has been carried

out for gravity based offshore storage

tanks.

Purpose built floaters can also be

tailor made relative to optimum storage

capacity. Use of exisiting tonnage can

however represent a storage constraint.

Offshore terminals that are currently

under construction, based on FSRU`s

built on speculation, are generally to

small for full realisation of the terminals

commercial potential in terms of spot

cargo trading.

Fast-trackAs mentioned in the beginning of this

section, the fast track potential for

FSRU`s that where available in the

market was the most important

parameter for the two floating terminals

currently under development in Brazil.

A short period from investment to

revenues is a huge NPV advantage but

there are energy political aspects to such

decisions as well.

The evolving economy in Brazil is

fuelled by access to energy and the

prospect of gas shortage is urging quick

solutions.

Currently, the typical critical path for

an onshore re-gasification terminal is

about 40 months of construction prior to

approval. Add to that a typical permitting

process of two years, and we are currently

discussing facilities coming online in

2013.

This stands in vast contrasts to the

Brazilian developments scheduled to

come online in May 2008 following

contract award to Golar LNG in the early

spring of 2007.

This very limited time for construction

was possible from the fact that two

existing vessels where available of which

one already was under conversion to a

FSRU.

Currently there is a number of older

LNG carriers approaching the end of

their operational service life, while their

owners are looking for alternative use.

With a delivery time for vaporisers of

1-2 years, and the opportunity to start a

speculative conversion prior to obtaining

development permits for a specific site,

the lead time may prove one of the best

arguments for developing a floating re-

gasification terminal although this needs

to be weighted against the fact that most

vessels available for conversion has

smaller storage capacity than desirable

for most potential developments.

The alternative to conversion is of

course a new building. A new build FSRU

enables optimization of capacities and

features, and there are several potential

terminal developers that have reserved

building slots at the biggest and most

competent yards. However, the minimum

lead time would increase to 3-4 years.

Regas facilitiesFrom the discussion in the previous

sections, it is obvious that there are

commercial opportunities in offshore

developments of re-gasification

terminals.

However the realisation of projects

has been slower than many expected a

few years back. The reluctance to go first

in use of new technology has been a key

factor to such slow developments.

This is understandable as the

reliability of the supply chain is essential

in the LNG industry and the commercial

exposure for supply interruptions has

significantly higher consequences than

for e.g. crude oil trading, where

alternative sources of supply exists.

In principle, unproven technology

represents an increased project

development cost, as unproven

technology represent an increased risk.

The challenge is to quantify this cost and

as important reduce this risk.

RiskexThe statistical cost related to unplanned

repairs, maintenance and reduced or lost

regasification capacity can be termed as

RISKEX. Project investment decisions

are typically based on Capital

Expenditures (CAPEX) and Operational

Expenditures (OPEX), with little

consideration for the risk exposure.

By introducing a third component to

the economic “balance”, namely risk

expenditures (RISKEX), it is possible to

take a balanced, mature appraisal of the

uncertainties and risks involved that

may have detrimental consequences on

initial, intermediate and long-term

revenue streams.

By implementing risk management

plans and applying risk and reliability

techniques to re-gasification projects,

risks can be identified and managed. You

may chose to keep or even increase the

RISKEX if there are associated rewards

attributed to the extra RISKEX. You may

also choose to reduce the RISKEX as the

statistical cost of risk outweighs the

reward. An important side of a risk

management process is that decisions

Figure 2- Cost of Risk

p15-30:LNG 3 06/06/2008 12:42 Page 12

LNG journal • June 2008 • 27

REGASIFICATION

can be made with a better understanding

of the total risks and consequences.

Because operators are reluctant to use

unproved technology, a structured

technology qualification

process can provide cost

savings and assurances

regarding functionality and

reliability. Technology

qualification can play a

decisive role in the

development of offshore

LNG concepts.

The objective of

technology qualification is

to bring the technology to

the market by building

confidence. This will be

achieved by documenting

that the concept meets

specific reliability targets.

Technology qualification

is the process of proving the

technology will function

reliably within specific

limits. It is important to

follow a rational, systematic

and well-documented

approach to creating

confidence in novel

solutions. This should focus

on high-risk issues and on

reducing the risk of

unforeseen events.

The qualification can

be conducted in parallel

with the technology-

development project.

Through co-operation

between the technology

stakeholders, the

qualification work process

ensures all aspects of

the novel technology

are adequately addressed

and that the technology

is proved to comply

with stated functional

requirements and

reliability targets.

In this respect, known

technology in a new

application is also included.

An additional benefit of a

systematic approach is cost

savings during the

development phase – as

much as 90% of the cost of a

technology development

project is related to tests.

Experiences so far,

indicate that there are

only a few really important

parameters that affect the concept

selection in terms of onshore versus

offshore.

By addressing these limited number

of parameters properly in the concept

development phase, by quantifying the

cost of risk, assessing terminals actual

availability, and bring new technology to

the marked through risk based

qualification procedures, terminal

developers are likely to improve the

return on their investment. �

T H E 2 3 R D A N N U A L E U R O P E A N A U T U M N G A S C O N F E R E N C E

www.theeagc.com/lngj

25-26 November 2008 • Spazio Villa Erba • Lake Como • Italy

T H E L O N G E S T R U N N I N G A N N U A L G A S C O N F E R E N C E I N E U R O P E

HOSTED BY

ORGANISED BY

Bookings now being takenE A R L Y B I R D D E A D L I N E – 3 1 J U L Y 2 0 0 8

p15-30:LNG 3 06/06/2008 12:42 Page 13

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

COLD CLIMATE

The Kenai LNG plant, at latitude 60oN

in Alaska, has been operating

successfully since 1969, but until recently

has been the only major baseload

liquefaction plant in a cold or even

temperate region.

Now the Snøhvit LNG plant has

recently begun operations at 71˚N in

Norway, and another plant, Sakhalin II

LNG, is very close to start-up at 47˚N in

Russia. What differentiates these plants

from those operating further South?

Firstly, the annual average

temperature is low. Typically, this may be

around 0 to 5˚C rather than the 20-25˚C

experienced in the tropics. And secondly,

the seasonal variations can be very wide,

with ambient air varying from -40˚C in

winter to +30˚C in summer rather than

say +5˚C to +45˚C further South. Day-to-

night temperature variations can be

large as well.

BP’s recent studies on cold region LNG

production were focused on selection of

the liquefaction process and rotating

equipment.

However, there were additional results

in the areas of design for lower ambient

temperatures and the balancing of low

pressure gas flows around the plant.

We also looked at the need for

winterisation in both the construction

and operational stages, but those

measures are not addressed in this

article.

EnvironmentFigure 1a shows ambient air

temperature variation thoughout the

year in one of the locations we studied.

Seasonal temperature variations tend to

be greater anyway as you go further from

the equator.

But in addition, as all LNG plants are

by definition in coastal locations, air

temperature variations are damped by

the presence of water.

In extreme Northern (and Southern)

latitudes, once the sea surface has frozen

over, this mitigating effect is removed

and winter temperatures become more

like those of mid-continent locations. As

we shall see, this poses special challenges

for process, coolant and machinery

selection.

As a further challenge to the plant

designers and project managers, freezing

temperatures, snowfall and high winds

reduce on-site productivity, complicate

the transport of personnel and

equipment and extend the construction

schedule, while snow and ice loadings can

have a significant impact on building and

structure designs.

Plant performanceAs both air and seawater are colder in

winter, air/water cooler performance is

higher and more refrigerant can be

circulated, allowing more gas to be

liquefied, provided that the heat transfer

capacity of the main exchanger is not

exceeded.

This requires more compressor power,

but as gas turbine power is also greater

when the inlet air is colder, this should

not be a problem.

Figure 2 presents a typical seasonal

temperature profile (monthly averages as

used for plant design), and the

corresponding variation in theoretical

maximum plant output: +/- 10 percent

from the mean. This is for an air-cooled

plant.

How can such theoretical figures be

achieved? Firstly, to cover the winter

production peak (when coolant

temperatures are lowest), the gas supply

network from wellhead to plant fence

must be sized for the maximum flow,

regardless of the fact that it will only be

fully utilised for a few days per year - and

then only for part of each day.

Then the whole LNG plant, including

gas treatment facilities, will also have to

be designed for peak flow, and enough

ships will have to be procured to take

away the extra production in midwinter,

just when shipping is at a premium and

sea passages are at their most

challenging with storms and ice-covered

waters.

Some of this extra shipping capacity

may well be idle or on charter at low

rates every summer. So the economics of

following the theoretical production

profile, even if the choice of process and

cooling medium allows this, must be

examined in relation to all the

investments in the chain, not just the

liquefaction process.

Design temperatureIn practice, the plant will not be designed

for the winter peak, or even for the

average temperature of the coldest

month.

As we shall see, more detailed process

modelling shows that the process itself

will set a limit or “cap” to peak

production. Then there are at least three

further steps.

Firstly, sensitivities to lower peak

rates have to be run, to identify the trade-

off between the cost of additional ships,

supply rates, etc. and imperfect

utilisation of all this extra equipment

throughout the year.

Secondly, ways of mitigating the

summer production “trough” have to be

BP develops studied approach toliquefaction in an Arctic climateMartin Josten and John Kennedy

Figure 1: Ambient air temperature

Figure 2: C3/MR5mtpa plant theoretical maximum production

Figure 2: C3/MR5mtpa plant theoretical maximum production

p15-30:LNG 3 06/06/2008 12:42 Page 14

LNG journal • June 2008 • 29

COLD CLIMATE

devised. Thirdly, once the design point

has been selected, the selected system

has to be “rated” to predict its

performance at both extremes of

temperature, to establish the annual

output of LNG and the overall project

economics.

Figure 3 illustrates the effect on

annual throughput of setting different

“caps” on winter throughput for a given

plant.

Coolant selectionBroadly, we are looking at direct air

versus direct seawater cooling. Other

variants such as indirect seawater

cooling will fall in between, and may in

any case be needed for certain specific

sections of the plant for mechanical

reasons.

Air temperature will vary more widely

than water temperature, which is both

good and bad. It’s bad because the driving

temperature difference and hence the

heat transfer rate in the pre-cooling

refrigerant condensers will change.

This means the pre-cooling refrigerant

circulation will vary almost linearly with

ambient temperature, and the overall

refrigeration plant capacity will follow.

This means that there will be a large

“hole” in summer production, just when

spare shipping capacity is available.

Incidentally, this will also coincide with

weather conditions that are favourable

for plant turnarounds.

The mitigating factor is that some

advantage can potentially be taken of

sub-zero temperatures in winter.

Figure 1b shows some seawater

temperature data for different seasons

and water depths.

Note that depth-related temperature

data is not widely available, and this may

have to be obtained specially for the

chosen site by the project sponsor.

As large bodies of water are good heat

“sinks”, water temperature will tend to

vary less widely than the air above it,

particularly if the water can be obtained

from below about 10m depth.

However, water obviously cannot go

much below 0˚C, and therefore (counter-

intuitively, perhaps) the annual average

water temperature may be 2-3˚ higher

than for air. So although this will go some

way towards filling in the summer

production “trough”, the opportunity to

make up extra production in winter will

be limited.

Capital costs for seawater cooling tend

to be significantly higher than for air

cooling, and coupled with the

environmental sensitivity connected with

extracting seawater, this points towards

air cooling being generally the more

likely choice, except where space is

severely limited.

As the Sakhalin LNG plant is air-

cooled and the Snøhvit plant (on a small

island) is water-cooled, it will be

interesting to compare their performance

in practice.

Process selectionThe most widely available LNG processes

are divided between those which are pre-

cooled with propane and those with a

mixed refrigerant.

In the case of propane pre-cooling, the

refrigerant is a single, pure component,

and therefore its evaporating

temperature is more or less fixed, given

the practical limit of avoiding a vacuum

at the compressor inlet.

Therefore, the temperature to which

the process gas can be pre-cooled before

entering the main liquefaction exchanger

is limited in practice to around -35˚C.

The alternative of ethane pre-cooling

has also been proposed, which could

provide chilling down to -60˚C or so.

However, the critical temperature of

ethane is about 32˚C.

So it could work with a coolant whose

temperature never rises above around

20˚C in summer, but this effectively rules

out the use of air cooling in the location

studied.

Within the pre-cooling cycle, if colder

air is available, the air coolers and

condensers can process more refrigerant,

but then the circulation rate will be

limited by the compressor rating and

driver power. So compressor/driver sizing

will determine throughput.

On the other hand, if the pre-cooling

medium is a mixture of refrigerants, then

the mixture can be adjusted within

certain limits to change the molecular

weight and hence the condensing

temperature of the mix.

Thus in winter the lower ambient air

can be used to condense a lighter

refrigerant at a lower temperature. But

what about the compressor?

As the refrigerant is condensing at

lower temperature, this can be performed

at a lower pressure, so that the

compressor can move out along its curve

and process a greater refrigerant flow at

lower compression ratio - all within a

given shaft power. So overall

refrigeration duty can be increased to

take advantage of the winter conditions.

Figure 3 also illustrates the difference

between propane and mixed refrigerant

pre-cooling in this respect. Increased

output requires investment in larger

piping sizes, larger treatment facilities

and so on (which have not been examined

in this article) and adjustment of the

mixed refrigerant composition to keep

performance and efficiency optimised is a

challenge for plant operations.

However, the extra cargoes of LNG

produced using mixed refrigerant pre-

cooling can have a significant impact on

plant economics.

Train size limitsThe question that is often asked about

cold climate LNG plants is: “What about

large train sizes?” Intuitively, it seems

that with the opportunities for increased

process efficiency, more cargoes of LNG

can be delivered by a plant using

established equipment sizes.

Unfortunately, this is not

straightforward, because the limiting

piece of equipment is usually the main

cryogenic exchanger in the liquefaction

section.

If the liquefaction section of the plant

is cooling the process gas from say -35˚C

(with propane pre-cooling) to -160˚C

(ignoring end-flash effects), it is relatively

insensitive to ambient conditions.

It will be limited by its total “UA” (heat

transfer coefficient times surface area),

which is directly related to physical size

limits.

On the other hand, if the pre-cooling

cycle uses mixed refrigerant, this can be

used to pre-cool the gas to say -60˚C,

taking load away from the liquefaction

circuit and getting around that

bottleneck.

So very large Train sizes can be

envisaged without having to duplicate

the main exchanger or enlarge it beyond

proven limits.

Fuel gas balanceHaving colder ambient temperatures

available presents another problem

which may be a surprise. As will be

explained in the next section, not only

will the refrigeration process operate

more efficiently in cold weather, but gas

turbine drivers also consume less fuel

under these conditions. Overall fuel

consumption will be less and this is not a

problem in itself.

However, the fuel balance of an LNG

plant is quite delicate. Under normal

circumstances, as shown in Figure 4, fuel

gas is derived from several sources: a)

boil-off gas from the tanks, which is

determined by nearly constant heat

inleak through the tank insulation, and

by the degree of sub-cool in the LNG

rundown stream; b) excess return vapour

from ship loading; c) treated gas from the

upstream part of the plant; and d) end-

flash gas.

Of these streams, a) and b) are fixed by

design parameters such as insulation

thickness and loading line lengths, and

also partly by operating issues such as

the arrival of a ship with a warm cargo

hold, so the plant operator doesn’t have

much if any control over them if flaring

is to be avoided.

Stream c) provides a supply of fuel gas

at start-up, but can be cut back in steady

operation. So that leaves end-flash gas.

If the overall fuel gas usage is low,

then the plant operating conditions must

be trimmed to reduce end-flash gas. Why

is that a disadvantage?

End-flashing is a way of achieving the

final few degrees of cooling in the process

gas stream from the main liquefaction

exchanger before entering the storage

system.

Its pressure is reduced through a

Joule-Thompson valve or expander before

flowing into an intermediate flash drum.

Figure 4: Fuel gas balance

p15-30:LNG 3 06/06/2008 12:42 Page 15

The evolved vapour, rich in nitrogen, is

usually compressed and sent to the plant

fuel system.

Some 10o of cooling can be achieved in

this way, so that the exit temperature

from the main exchanger may be no

lower than -150˚C.

This reduces refrigeration compressor

load and increases the heat transfer

performance of the exchanger, and hence

(for a fixed surface area) increases its gas

throughput capacity.

Conversely, if there is no such disposal

route for the end-flash gas, the process

gas will have to be cooled to nearer -

160˚C in the main exchanger, which will

restrict its gas throughput capacity.

So in a cold climate with a fuel-

efficient plant, the capacity in million

tonnes per annum of a plant with a given

exchanger may actually be significantly

less.

This is important if you are trying to

maximise LNG Train output within the

limits of available exchanger sizes. What

can be done about this?

One possible measure is to re-adjust

plant operation every time a ship loads,

because stream b) above is intermittent.

It is much larger than stream a), and sets

the worst condition for fuel gas balancing,

mainly because of the large heat output

from the loading pumps.

But in between ship-loading

operations, there is more “ullage” in the

fuel system to absorb end-flash gas.

Unfortunately, this is scarcely practical

as it means a major adjustment to plant

performance every few days, including

mixed refrigerant compositional change

which cannot be done rapidly.

Another measure is to keep the end-

flash flow constant and recycle it to the

front end of the liquefaction plant. This

means the end-flash flow can be

maximised, and it does increase main

exchanger throughput performance -

albeit at the expense of a fairly large

recycle compressor.

Note that it does not increase the

overall thermal efficiency of the plant, as

the power saved in the refrigeration

circuit is simply added back into the end-

flash gas compressor.

And finally, there may be another

disposal route for the end-flash gas such

as a domestic gas market. If this can be

supplied at lower pressure, then there

will be gains in both Train performance

and thermal efficiency, as there will be

less power consumption for compression.

A possible problem could be if the

nitrogen content exceeds the market

specification, but this can be overcome by

a two-stage flash, directing the higher

nitrogen stream from the first stage to

plant fuel.

Machinery selectionSeasonal temperature variation has a big

effect on gas turbine performance,

because colder inlet air is denser, the

mass flow is greater and it requires less

power to compress it, leaving more power

available to the compressor shaft.

So gas turbine-driven compressor

power can vary by +5 percent for a

temperature variation of -10˚C. This is

good news in winter but bad news in

summer, when production can be limited

by turbine performance.

One possible mitigation is to run the

starter motor as a helper in summer, if

there is enough electric power available.

Electric motor drivers are relatively

insensitive to ambient temperature,

apart from possible limits to the stator

winding cooling system. So although they

do not gain much from a cold winter, they

also lose less power in summer.

This flatter profile, if well “tuned” to

refrigeration performance, will result in

higher annual average production

without putting such a strain on shipping

and other facilities.

Higher overall availability will further

increase the number of cargoes of LNG

that can be delivered.

Obviously, the electric power is

supplied from gas turbine generators in

the power station, but it is assumed that

there is enough spare capacity to provide

the needed electric power in all seasons.

Where necessary, the spare generation

machine can be run: this will require

careful maintenance scheduling to avoid

machinery outage in the warmest

summer period.

There are other significant benefits

with electric motor drives, such as the

removal of large fired machines from the

process area, the ability to specify the

shaft power to fit the process,

compactness, combined cycle fuel

efficiency and full-load soft start

facilities.

Together, these features make an all-

electric solution potentially very

attractive in Northern latitudes, if a cost-

effective power scheme can be achieved.

Conclusions Northern latitudes offer colder average

ambient temperatures and hence the

possibility of larger and more efficient

LNG Trains.

However, apart from the obvious

construction and operational issues posed

by severe weather, they also pose the

challenge of wide temperature variations.

BP has been studying these challenges

extensively with various contracting

partners.

The indications are that air cooling

yields the best overall economics in most

situations and that a mixed refrigerant

pre-cooling cycle offers the best flexibility

to take advantage of lower and widely

varying ambient temperatures.

It can also be seen that electric motor

drives will provide additional LNG

cargoes, not only through higher

efficiency and availability, but also

through a smoother annual production

profile which will place less strain on

supporting facilities. �

Martin Josten and John Kennedy of BPwould like to acknowledge thecontribution by Chiyoda Corp. ofYokohama, Japan, to these studies and thecompletion of this article.

COLD CLIMATE

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

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In this issue:1

China shapes firm LNG terminal strategy

as demand forecasts

soarJohn McKay, LNG Journal Editor,

and David Hayes, Asia Correspondent, Shanghai6

LNG importer focus

turns to US interchangeability rulesKirstin E. Gibbs, David L. Wochner

and Meagan Keiser of Sutherland

Asbill& Brennan LLP, Washington D.C.

12 Trinidad’s LNG expansion plans clouded by gas reserves concernLinda Hutchinson-Jafar, Port of Spain, Trinidad

17 A round-up of latest

events, company and

industry newsNews Index

33 CB&I helps the UK build up LNG import

network and storage

capacityPeter Bennett, Mike Whitney and

Barbara Weber, CB&I37 Real Time Engineering

delivers LNG management for two

UK terminalsRobert McSaveney

43 Aker Kvaerner proposes the product

treatment options for

LNG terminalsK. Shah, Technical Vice President,

Aker Kvaerner, Houston, and G. Joshi, Project Manager, AMEC

Paragon, Houston (formerly of

Aker Kvaerner Inc.)48 World Carrier Fleet:

More new-builds commissioned54 Tables of Liquefaction

and LNG Receptionterminals worldwide

November/December 2007

60 pagesessential LNGnews!China shapes firm LNG terminal

strategy as demand forecasts soar

China will have nine LNG terminals to

meet rising demand as its coastal import

network begins to take shape now that

LNG has already become a strategic fuel.

More than 16 LNG terminal projects

were proposed at one stage, though the

government later insisted that LNG

supplies must be secured before approval

to begin construction is given for any

project.

The current Chinese LNG network is

expected to be restricted to the nine LNG

terminals because of future global LNG

supply constraints.Most involve China National Offshore

Oil Corp. and PetroChina and are two-

phase ventures consisting of initial

facilities to import from 2.5 million tonnes

per annum to 3 MTPA and with plans to

immediately begin doubling capacity.

CNOOC operates China’s first LNG

terminal on the Pearl River delta at

Dapeng in Guangdong Province and

currently is constructing two more

import terminals in Fujian Province and

near the city of Shanghai.The company also plans to build two

other LNG receiving terminals at Ningbo

in Zhejiang Province on the east coast

and at Zhuhai in Guangdong.Offtake searchCNOOC, which has agreements to import

LNG from Australia, Indonesia and

Malaysia for its first three terminals is

now looking for LNG supplies for its

newer projects.Talks have been held with various

potential suppliers, including Qatar and

Indonesia.In addition, the company has signed

framework deals to buy spot LNG cargos

from several suppliers including France’s

Total and Royal Dutch Shell, though

details of cargoes, timing and prices have

not been announced.Construction work is nearing

completion in Fujian Province in

southern China on CNOOC’s second

LNG terminal near the provincial capital

Fuzhou.

Located in the coastal city of Xiuyu,

the terminal is being built with a Phase I

capacity to handle 2.6 MTPA of LNG per

year, while a Phase II expansion will

double the terminal capacity.

Chicago Bridge & Iron of the US was

awarded the $140M contract for the

design and construction of Fujian

terminal system plus a $100M EPC

contract as far back as April 2005 to build

two 160,000 cubic metres capacity full-

containment LNG storage tanks at the

Xiuyu terminal.The terminal is scheduled to begin

commercial operations in 2008. When

completed, it will be owned and operated

by CNOOC Fujian LNG Co, a joint

venture company in which CNOOC has a

60 percent shareholding, while the Fujian

provincial government-backed Fujian

Investment and Development Corp. holds

a 40 percent interest.The terminal will be linked to a 367

kilometres-long high-pressure transmis-

sion pipeline running through Fujian.

The pipeline is planned to connect to

the south of Fujian with a transmission

pipeline section running north from

CNOOC’s Dapeng terminal.Fujian linkIn northeast Fujian, at a site near the

coastline, a gas transmission line

running north from the Xiuyi terminal

will connect with a pipeline planned for

construction in Zhejiang Province. This

will link the Xiuyi terminal with

CNOOC’s planned Ningbo facility.

Natural gas from Xiuyi will be

supplied to three gas-fired power plants

totalling 3,600 megawatts that will be

built during the project's first phase. The

three power plants will be built as

combined-cycle stations.Regasified LNG also will be supplied

to household customers in five major

cities in Fujian – Fuzhou, Xiamen,

Quanzhou, Putian and Jinjian.

CNOOC will import 2.6 MTPA of LNG

from the BP-operated Tangguh LNG

project in Indonesia that comes on

stream in 2008, though the company has

had to agree to pay a higher price for the

Indonesian LNG than originally planned.

China's LNG import network is emerging, and though some completion dates

are fluid competition will increase for regional and global LNG supplies

John McKay, LNG Journal Editor, and David Hayes, Asia Correspondent, Shanghai

p15-30:LNG 3 06/06/2008 12:43 Page 16

Abadi 135,000 Brunei STASCO Mitsubishi Jun-02 Brunei S Moss 5 Brunei-Japan Brunei LNG 2023

Gas Carriers Nagasaki

Al Aamriya 210,100 J5 Consortium K Line/ Daewoo Feb-08 Marshall I DRL GT NO 96 4 Qatar-Japan Qatargas

NYK Line

Al Areesh 151,700 Teekay LNG Teekay LNG Daewoo Jan-07 Qatar S GT NO 96 4 Ras Gas II Various 2032

Qatar-Europe

Al Biddah 135,275 J4 Consortium Mitsui Kawasaki Nov-99 Japan S Moss 5 Qatar-Japan Qatargas 2024

OSK Line Sakaide

Al Daayen 151,70 Teekay LNG Teekay LNG Daewoo Apr-07 Qatar S GT NO 96 4 RasGas II Various 2032

Qatar Europe

Al Deebel 145,000 Peninsular LNG Mitsui OSK Samsung Dec-05 Bahamas S TZ Mk. III 4 Qatar-Italy Qatargas RasGas II 2031

Line

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

Al Ghariya 210,100 ProNav ProNav Daewoo Feb-08 Germany DRL GT No. 96 4 Qatar-Atl’c Basin Qatargas

Al Gharaffa 216,200 OSG/Nakilat OSG Hyundai Jan-08 Marshall I. DRL TZ Mk. III 4

Al Hamra 137,000 National Gas National Gas Kvaerner- Jan-97 Liberia S Moss 4 Abu Dhabi- ADGAS Natural Gas 2022

Shipping Shipping Masa Japan Shipping

Al Jasra 137,100 J4 Consortium NYK Line Mitsubishi Jul-00 Japan S Moss 5 Qatar-Japan Qatargas 2025

Nagasaki

Al Jassasiya 145,700 Maran-Nakilat Maran Daewoo May-07 Greece S GT No 96 4 Qatar-Various RasGas 2027

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

Shipping Shipping Chiba Japan Shipping

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

Nagasaki

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

-Various

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

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

Sakaide

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

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

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

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

Line Nagasaki

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

Line Sakaide

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

Line

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

NYK Line NSL Japan

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

NYK Line NSL Japan

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

NYK Line NSL Japan

Annabella 35,500 Chemikalien Chemikalien La Seyne May-75 Liberia S GT NO 82 5 Libya-Spain Sirte Oil Enagas 2004

Seetransport Seetransport

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

Discoverer Chiba

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

Hoegh LNG Nagasaki

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

Princess Hoegh LNG Nagasaki

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

Shipping Japan /Marathon /Marathon

Arctic 140,000 K Line K Line Kawasaki Jul-06 Bahamas S Moss 4 Norway- Statoil Snohvit Sellers 2026

Voyager Spain-US

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

Chihani Hyproc Turkey

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

Nagasaki -Japan

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

CARRIER FLEET

LNG journal • June 2008 • 31

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

carrier m3 Date Plant System tanks Route

p31-36:LNG 3 06/06/2008 12:47 Page 1

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

CARRIER FLEET

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

Tankers

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

Algeria

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 Jan-04 Spain S GT NO 96 4 Trinidad- Atlantic Repsol 2024

Marpetrol Marpetrol Sestao Spain LNG

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 Bluesky LNG Corp TMT Daewoo Jan-06 Panama S GT No 96 4 M/East-Taiwan

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

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

Marpetrol Marpetrol Puerto Real

Castillo 138,000 Elcano Elcano IZAR Nov-03 Spain S GT NO 96 4 Algeria-Spain Sonatrach Enagas 2007

de Villalba Puerto Real

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

Spirit Partners Partners Sestao Spain LNG

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

Century 29,588 BW Gas BW Gas Moss Moss Dec-74 Norway D Moss 4 Algeria-Greece Sonatrach DEPA 2010

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

Cinderella 25,500 Taiwan Marine Bluesky LNG Le Trait Jun-65 St. Vincent S Worms 7 Libya-Spain Sirte Oil Enagas 2004

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 I. S TZ Mk. III 4 Various

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

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

Energy

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

Dewa Maru 125,000 J3 Consortium K Line Mitsubishi Jul-84 Japan S Moss 5 Indonesia Pertamina Tepco 2005

Nagasaki -Japan

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

Ltd. OSK Line

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 Mitsui Mitsui Oct-04 Japan S Moss 4 Qatar-Spain Qatargas 2024

OSK Line Chiba

Dwiputra 127,385 Humpuss Humolco Mitsubishi Mar-94 Bahamas S Moss 4 Indonesia Pertamina 2010

Consortium Nagasaki -Japan

Echigo Maru 125,570 J3 Consortium NYK Line Mitsubishi Aug-83 Japan S Moss 5 Indonesia Pertamina Tepco 2005

Nagasaki -Japan

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

Gaz de France Dreyfus France

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 Pertamina CPC 2014

Consortium Nagasaki -Taiwan

Energy 145,000 Tokyo LNG Mitsui Kawasaki Mar-05 Japan S Moss 4 Australia Darwin Togas 2025

Advance Tankers OSK Line Sakaide -Japan

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

Frontier Tankers OSK Line Sakaide

Energy 145,000 Mitsui OSK Line Mitsui Kawasaki NOV-06 Japan S Moss 4 Indonesia Bayu Undan LNG 2026

Progress OSK Line -Japan

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

Excelerate

Excel 138,106 Exmar/ Exmar Daewoo Sep-03 Belgium S GT NO 96 4 Exports Oman Gas 2009

Mitsui OSK Line from Oman

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 2025

Energy

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

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

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

OSK Line

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

Nagasaki

p31-36:LNG 3 06/06/2008 12:47 Page 2

LNG journal • June 2008 • 33

CARRIER FLEET

Galeomma 126,540 Shell Shipping STASCO Newport Dec-78 Singapore S TZ Mk. I 6 Oman-Spain Oman Iberdrola 2007

News

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

Partners Partners

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

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

Energy d’Atlantique

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

Nagasaki

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- ADGAS Natural Gas 2021

Shipping Shipping Chiba Japan Shipping

Gimi 126,277 Golar LNG Golar LNG Moss Dec-76 UK S Moss 6 Trinidad-U.S. Atlantic BG 2020

Stavanger LNG

Golar Freeze 125,850 Golar LNG Golar LNG HDW Feb-77 UK S Moss 5 Trinidad-U.S. Atlantic LNG BG 2008

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

Chinese Pet. Nagasaki -Taiwan

Golar Spirit 129,000 Golar LNG Golar LNG Kawasaki Sep-81 UK S Moss 5 Indonesia Pertamina Kogas 2008

Sakaide -Korea

Golar Winter 138,250 Golar LNG Golar LNG Daewoo Apr-04 Norway S GT NO 96 4

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

Gracilis 138,830 Golar LNG Golar LNG Hyundai Jan-05 Bermuda S TZ Mk. III 4 Shell 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 Mos 4

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

Grandis 145,700 Golar LNG Golar LNG Daewoo Jan-06 UK S GT NO 96 4 Shell 2011

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

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

Taek -Korea

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

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

Hassi R'Mel 40,850 SNTM-Hyproc SNTM- La Seyne Jan-71 Algeria S GT NO 82 6 Various Sonatrach 2013

Hyproc

Hilli 126,227 Golar LNG Golar LNG Moss Dec-75 UK S Moss 6 Trinidad-U.S. Atlantic LNG BG 2023

Stavanger

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

Spirit LNG Partners Partners

Hoegh 87,600 Hoegh LNG Hoegh LNG Moss Nov-74 Norway S Moss 5 Trinidad-U.S. Atlantic LNGSuez 2018

Galleon Stavanger

Hoegh 125,820 Hoegh LNG Hoegh LNG HDW Oct-77 Norway S Moss 5 Indonesia Pertamina Kogas 2008

Gandria -Korea

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

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

Cosmopia

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

Greenpia -Korea

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

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

Technopia

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

Utopia -Korea

Iberica 138,000 Knutsen OAS Knutsen Daewoo Aug-06 Norway S GT 96 4 Qatar-various various Repsol/ 2009

Knutsen OAS 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 Enagas 2004

Seetransport Seetransport

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

Shipping Shipping Nagasaki -Japan Shipping

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

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

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

Tankers Domestic Trade

Khannur 126,360 Golar LNG Golar LNG Moss Jul-77 UK S Moss 6 Qatar-Spain Qatargas BG 2019

Stavanger

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

Maru Sakaide -Japan

Laieta 40,000 Auxiliar Anglo-East- Astano May-70 Panama S Esso 4 Algeria-Spain Sonatrach Enagas 2007

Maritima ern Mgmt

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

N'Soumer Gas MOL Sakaide Algeria

p31-36:LNG 3 06/06/2008 12:47 Page 3

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

CARRIER FLEET

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

M'Hidi Hyproc Turkey

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

Transport ern Mgmt France/Turkey GdF/BOTAS

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

Transport ern Mgmt

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 ProNav . GD Quincy Jun-77 Marshall I. S Moss 5

Japan Ship Mgmt

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

Japan Ship Mgnt

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

Transport Nigeria

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

Nigeria

LNG Bonny 133,000 Bonny Gas STASCO Kockums Dec-81 Bermuda S GT NO 88 5 Nigeria-Spain/ Nigeria LNG Enagas/ 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 Pertamina 2010

Mgmt. -Japan

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

River Transport ern Mgmt

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

Transport News France/Turkey GdF/BOTAS

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-East- GD Quincy May-80 Bahamas S Moss 5 Nigeria-Spain/ Nigeria LNG Enagas/ 2019

Transport ern Mgmt France/Turkey GdF/BOTAS

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

Genoa France

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

Nigeria

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

Transport France/Turkey GdF/BOTAS

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

Sakaide -Japan

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

Japan Ship Mgmt. Islands -Japan

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

J3 Consortium Nagasaki Japan

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 Enagas/ 2019

Transport France/Turkey GdF/BOTAS

LNG Leo 126,400MOL/LNG ProNav GD Quincy Dec-78 Marshall S Moss 5 Indonesia Pertamina 2010

Japan Ship Mgmt. Islands -Japan

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

Sestri

LNG Libra 126,400 MOL/LNG ProNav GD Quincy Apr-79 Marshall S Moss 5 Indonesia 2010

Japan Ship Mgmt. Islands -Japan

LNG Lokoja 148,300BW Gas BW Gas Daewoo Dec-06 Bermuda S GT No. 96 4 Atlantic Basin Nigeria LNG Various 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 LNG Various 2026

Nigeria

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

Genoa

LNG Pioneer 138,000 Mitsui OSK Mitsui OSK Daewoo Jul-05 Luxemb'g S GT NO 96 4 Exports from Idku BP 2008

Line Line Egypt

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

Harcourt Transport France/Turkey GdF/BOTAS

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

Portovenere Sestri

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

Niger Transport Eastern Mgmt.

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

Orashi Nigeria

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

Transport

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

Transport

LNG Taurus 126,300 MOL/LNG ProNav GD Quincy Aug-79 Marshall S Moss 5 Indonesia 2010

Japan Ship Mgmt. Islands - Japan

p31-36:LNG 3 06/06/2008 12:47 Page 4

LNG journal • June 2008 • 35

CARRIER FLEET

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

Consortium Line Nagasaki - Japan

LNG Virgo 126,400 MOL/LNG ProNav GD Quincy Dec-79 Marshall S Moss 5 Indonesia Pertamina 2010

Japan Ship Mgmt. Islands - Japan

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

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

Partners Partners Puerto Real

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

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

Laffan

Maran Gas 145,000 Kristen Maran Gas Daewoo Jul-05 Bermuda S GT NO 96 4 Qatar-Europe Qatar RasGas II 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 Hoegh LNG Newport Jun-79 Bahamas S TZ Mk. I 6 Trinidad-U.S Atlantic LNG Suez 2019

Shiping News

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

Victoria

Methane Heather145,000 BG BG Samsung Jul-07 Bermuda S Tz Mk. III 4 Eq.Guinea-US Eq.Guinea LNG 2027

Sally

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

Elizabeth Hellenic

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

Elin International International

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

Lake Charles -Atlantic Basin

Methane 145,000 Australian Bank Ceres Samsung Aug-06 Bermuda S TZ Mk. III 4 Various Engas MSL 2026

Lydon Volney -Leased to BG Hellenic

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

Eagle Atlantic Basi

Methane Princess138,000 Golar LNG Golar LNG Daewoo Aug-03 UK S GT NO 96 4 Trinidad-Spain Atlantic LNG BG 2034

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

Andre Hellenic

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

Elizabeth Guinea - US

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

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

Boulaid Hyproc

Mourad 126,130 SNTM-Hyproc SNTM- Atlantique Jul-80 Algeria S GT NO 85 5 Algeria- Sonatrach Suez 2006

Didouche Hyproc Belgium

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

Shipping Shipping Masa -Japan Shipping

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

Shipping Shipping Masa -Japan ving facility

Muscat LNG 149,170 Oman Gas Mitsui OSK Kawasaki Mar-04 Japan S Moss 4 Oman- Oman Gas Shell 2007

/MOL Line Sakaide Spain

Neo Energy 150,000 Tsakos Tsakos Hyundai Feb-07 Liberia S Moss 4 Available

Nizwah LNG 145,000 Oryx LNG Mitsui OSK Kawasaki Dec-05 Japan S Moss 4 Oman- Oman Gas Osaka Gas 2026

Carriers Line Sakaide Japan

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

Stavanger Spain

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- NWS IGTC 2008

Sanderling Nagasaki Japan

Northwest 127,500 Australia LNG ALSOC Mitsui Feb-93 Australia S Moss 4 Australia- NWS IGTC 2008

Sandpiper Chiba Japan

Northwest 127,450 Australia LNG STASCO Mitsubishi Nov-92 Bermuda S Moss 4 Australia- NWS IGTC 2008

Seaeagle Nagasaki Japan

Northwest 127,500 Australia LNG BP Shipping Kawasaki Sep-91 Bermuda S Moss 4 Australia- NWS IGTC 2008

Shearwater Sakaide Japan

Northwest 127,747 Australia LNG ALSOC Mitsui Sep-90 Australia S Moss 4 Australia- NWS IGTC 2008

Snipe Chiba Japan

Northwest 127,600 Australia LNG ALSOC Mitsubishi Dec-94 Australia S Moss 4 Australia- NWS IGTC 2008

Stormpetrel Nagasaki Japan

Northwest 127,708 J3 Consortium Mitsui Mitsui Nov-89 Japan S Moss 4 Australia- NWS IGTC 2008

Swallow OSK Line Chiba Japan

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

Swan Transport from Australia

Northwest 127,590 J3 Consortium NYK Line Mitsubishi Sep-89 Japan S Moss 4 Australia- NWS IGTC 2008

Swift Nagasaki Japan

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

Transport Nagasaki Japan

p31-36:LNG 3 06/06/2008 12:47 Page 5

36 • LNG journal • The World’s Leading LNG journal

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

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

Shipping Nagasaki Japan

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

OAS Norway Vest

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

Shipping /Marathon /Marathon

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

Puteri Delima 130,400 M.I.S.C. M.I.S.C. Atlantique Jan-95 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG II 2015

Puteri Delima 137,100 M.I.S.C. M.I.S.C. Mitsui Chiba Apr-02 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG III 2023

Satu

Puteri Firuz 130,400 M.I.S.C. M.I.S.C. Atlantique May-97 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG II 2018

Puteri Firuz 137,100 M.I.S.C. M.I.S.C. Mitsubishi Sep-04 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG III 2024

Satu Nagasaki

Puteri Intan 130,400 M.I.S.C. M.I.S.C. Atlantique Aug-94 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG II 2015

Puteri Intan 137,100 M.I.S.C. M.I.S.C. Mitsubishi Dec-01 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG III 2023

Satu Nagasaki

Puteri Mutiera 137,100 M.I.S.C. M.I.S.C. Mitsui Chiba Apr-05 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG III 2025

Satu

Puteri Nilam 130,400 M.I.S.C. M.I.S.C. Atlantique Jun-95 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG II 2016

Puteri Nilam 137,100 M.I.S.C. M.I.S.C. Mitsubishi Sep-03 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG III 2023

Satu Nagasaki

Puteri Zamrud 130,400 M.I.S.C. M.I.S.C. Atlantique May-96 Malaysia S GT NO 96 4 M’sia-Japan Petronas MLNG II 2017

Puteri Zamrud 137,100 M.I.S.C. M.I.S.C. Mitsui Apr-87 Malaysia S GT NO 96 4 M’sia-Japan Atlantic LNG Enagas 2020

Satu Chiba

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

LNG Ltd. OSK Line

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

Abane Hyproc France

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

MOL OSK Line

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 Ind’sia-Japan Petamina 2011

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

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

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

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

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

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

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

Shipping Shipping Sakaide Japan Shipping

Shinjyu Maru 2,540 Shinwa Shinwa Imabari Aug-03 Japan D Cylinders 2 Japanese Shinwa

No. 1 Chemical Co. Marine Higaki Domestic Trade Chemicals

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

Maritime Maritime

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

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

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

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

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

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

MOL Line Nagasaki

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 Ind’sia-Japan Pertamina 2020

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

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

Tenaga Dua 130,000 M.I.S.C. M.I.S.C. Dunkerque Aug-81 Malaysia S GT NO 88 5 M’sia-Japan Petronas MLNG 2205

Tenaga Empat 130,000 M.I.S.C. M.I.S.C. La Seyne Mar-81 Malaysia S GT NO 88 5 M’sia-Japan Petronas MLNG 2007

Tenaga Lima 130,000 M.I.S.C. M.I.S.C. La Seyne Aug-81 Malaysia S GT NO 88 5 M’sia-Japan Pertamina 2010

Tenaga Satu 130,000 M.I.S.C. M.I.S.C. Dunkerque Sep-82 Malaysia S GT NO 88 5 M’sia-Japan Petronas MLNG 2007

Tenaga Tiga 130,000 M.I.S.C. M.I.S.C. Dunkerque Dec-81 Malaysia S GT NO 88 5 M’sia-Japan Petronas MLNG 2006

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

Shipping Shipping Masa Japan Shipping

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

Navigation Maritime

Wakaba Maru 125,000 J3 Consortium K Line Mitsui Chiba Apr-85 Japan S Moss 5 Ind’sia-Japan Pertamina Tepco 2009

YK Sovereign 127,125 SK Shipping SK Shipping Hyundai Dec-94 Panama S Moss 4 Ind’sia-Korea Pertamina Kogas 2015

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

p31-36:LNG 3 06/06/2008 12:47 Page 6

Sponsors:

Contact:

Rob Percival

CWC Associates Limited

Tel: +44 20 7978 0078

Fax: +44 20 7978 0099

Email: rpercival@wgc2009.com

Website: www.wgc200.com

p37-44:LNG 3 06/06/2008 12:56 Page 1

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

� The capacity given is either the total existing or planned vaporization capacity (baseload and peak), converted to an equivalent annual throughput in million tonnes per annum (mtpa), or, in the case of those planned terminals where the available data is limited to a planned annual capacity, the capacity in the table may be either baseload or peak.

� For expansions to existing terminals the numbers given for capacity, and for numbers of storage tanks and their capacity, are those for the extra facilities associated with that expansion, not for the total terminal facilities after expansion.

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

Any comments on the tables, andcorrections/additional information fromterminal shareholders and projectdevelopers would be most welcome, andshould be sent to John McKay e-maileditor@lngjournal.com

Tables of reception terminalsLNG Reception Terminals

Total StorageCountry Location Owners Start up Vaporization No.of Total

(Project) capacity Tanks Capacity m3

mtpa

Belgium Zeebrugge Fluxys 1987 7.4 4 380,000

China Guangdong CNOOC,BP 2006 3.7 2 320,000

Dominican

Republic Andres AES 2003 2 1 160,000

France Fos-sur-Mer Gaz de France 1972 4 3 150,000

Montoir Gaz de France 1980 8 3 360,000

Greece Revithoussa DEPA 2000 2 2 130,000

India Dahej Petronet LNG 2004 5 2 320,000

Hazira Shell India 2005 5 2 320,000

Italy Panigaglia Snam 1969 2.4 2 100,000

Negishi Tokyo Gas 1969 11 14 1,180,000

Sodegaura Tokyo Gas 1973 28 35 2,660,000

Ohgishima Tokyo Gas 1998 5 3 600,000

Higashi-Ohgishima Tokyo Electric 1984 15 9 540,000

Futtsu Tokyo Electric 1985 20 10 1,110,000

Yokkaichi LNG Chubu Electric 1988 7 4 320,000

Kawagoe Chubu Electric 1997 8 4 480,000

Yokkaichi Works Toho Gas 1991 0.7 2 160,000

Chita LNG Joint Toho Gas, Chubu Electric 1978 8 4 300,000

Chita LNG Toho Gas, Chubu Electric 1983 12 7 640,000

Chita - Midorihama Toho Gas 2001 5 1 200,000

Senboku I Osaka Gas 1972 2.4 4 180,000

Senboku II Osaka Gas 1977 13 18 1,585,000

Himeji Osaka Gas 1984 5 8 740,000

Japan Himeji LNG Kansai Electric 1979 8 7 520,000

Yanai Chugoku Electric 1990 2.4 6 480,000

Niigata Nihonkai LNG, Tohoku Electric 1984 10 8 720,000

Oita Oita Gas, Kyushu Electric 1990 5 5 460,000

Tobata Kitakyushu LNG 1977 6 8 480,000

Fukuoka Saibu Gas 1993 0.9 2 70,000

Sodeshi Shizuoka Gas 1996 0.9 2 177,000

Hatsukaichi Hiroshima Gas 1996 0.5 2 170,000

Kagoshima Nippon Gas 1996 0.5 2 136,000

Shin-Minato Sendai City Gas 1997 0.8 1 80,000

Nagasaki Saibu Gas 2003 0.13 1 36,000

Sakai Kansai Electric, Cosmo OIl 2006 2.7 3 420,000

Mizushima Nippon Oil,Chugoku Electric 2006 0.6 1 160,000

Pyeong-Taek Korea Gas Corp. (Kogas) 1986 18 10 1,000,000

Kwangyang POSCO 2005 1.7 2 300,000

Korea Incheon Kogas 1996 29 18 2,480,000

Tong-Yeong Kogas 2002 10 5 700,000

Mexico Altamira Shell, Total, Mitsui 2006 3.6 2 300,000

Portugal Sines Transgas Atlantico 2003 5 2 240,000

Puerto Rico Penuelas Edison, Mission Energy, Gas Natural 2000 2.7 1 160,000

Barcelona Enagas 1969 8 6 540,000

Spain Huelva Enagas 1988 3 4 460,000

Cartagena Enagas 1989 4 3 297,000

Bilbao BP, Iberdola, Repsol, EVE 2003 5 2 300,000

Sagunto Union Fenosa, Endesa,Iberdola, Oman Oil 2006 4.8 2 300,000

Reganosa, Ferrol Union Fenosa, Endesa,Sonatrach,Tojeiro 2006 2.6 2 300,000

Taiwan Yung-An C.P.C. 1990 20 6 690,000

Turkey Marmara Ereglisi Botas 1994 4 3 255,000

Izmir EgeGaz 2006 3 2 280,000

Everett Suez LNG NA 1971 5 2 155,000

Lake Charles Southern Union 1982 9 4 425,000

USA Elba Island Southern LNG 2001 4 4 351,000

Cove Point* Dominion 2003 7.7 5 370,000

Gulf Gateway*

(offshore RVs, Gulf) Excelerate Energy 2005 4 * *

UK Isle of Grain National Grid 2005 3.3 4 200,000

TABLES

38 • LNG journal • The World’s Leading LNG journal

p37-44:LNG 3 06/06/2008 12:56 Page 2

LNG journal • June 2008 • 39

TABLES

Bahamas Freeport, Grand Bahama Suez, FPL Group, El Paso 2009 2 360,000

Ocean Cay AES Ocean Express 2008

Brazil Suape GNL do Nordeste : Shell, Petrobras 2009 1 160,000

Canada Bear Head US Venture Energy 2007 2 360,000

Cacouna LNG, Quebec TransCanada, Petro-Canada 2009 2 320,000

Goldboro, Keltic Petrochemicals

Goldboro Maple LNG 4Gas 2010 3

Nova Scotia PEV International R&D . 2008

Kitimat, B.C. Galveston LNG 2008 2 142,000

Texada Island, Nr. Vancouver WestPac LNG Corp., 2013

Canaport, Saint John, N.B. Irving Oil, Repsol 2008 3 480,000

Rabaska, Quebec Gaz Métro, Gaz de France & Enbridge 2010 2 320,000

Chile Quintero Enap 2008

China Fujian CNOOC, Fujian Investment & Development 2008 2 320,000

Shenzhen, Guangdong (expansion) CNOOC 2008 3 480,000

Hainan LNG CNOOC 2009

Shanghai CNOOC, Shenergy Group 2008 2 320,000

Tianjin CNOOC

Hebei CNOOC

Liaoning, Dalian PetroChina Ltd 2011 2

Ningbo, Zheijang CNOOC 2009

Yancheng, Jiangsu CNOOC 2010

Yingkou, Liaoning CNOOC 2010

Shantuo, Guangdong CNOOC 2010

Guangxi China National Petroleum Corp

Qingdao, Shangdong Sinopec 2009

Rudong, Jiangsu Sinopec, Petrochina 2010

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

Cyprus Vassiliko Cyprus Government 2009

France Fos Cavaou Gaz de France, Total 2009 3 330,000

Le Havre Verding/Poweo/ Gaz de Normandiem (Studies) 2011

Bordeaux (Le Verdon) 4Gas 2011

Marseilles (Fos-Sur-Mer) Royal Dutch Shell (Studies)

Le Havre (Antifer) Poweo/E.ON Ruhrgas/ Verbund/CIM 2012

Germany DFTG Willemshaven 2011 2 320,000

Honduras Puerto Cortes AES 2008

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

Mangalore ONGC 2010+

Kochi, Kerala Petronet LNG 2011 220,000

Ennore, Tamil Nadu GAIL, CPCL, IOC

Indonesia Cilegon, West Java PLN, Pertamina 2008

Italy Porto Levante (offshore GBS) ExxonMobil, Qatar Petroleum, Edison Gas 2008 2 250,000

Brindisi BG 2011 2 320,000

Livorno (offshore FSRU) OLT , Falck 2010

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

Taranto Gas Natural 2009 2 300,000

Priolo/Augusta/Melilli, Shell Energy Europe,

Sicily ERG Power & Gas 2010

Monfalcone (offshore) Endesa 2010

Jamaica Port Esquivel, Old Harbour Petroleum Corporation of Jamaica 2010

Japan Okinawa Okinawa Electric Power 2010

Shikoku/Sakaide LNG Shikoku Electric Power, Cosmo Oil Co., 2010

Shikoku Gas Co.

Pyeong-Taek (expansion) Kogas 2008 4 560,000

Korea Tong-Yeong (expansion) Kogas 2006 5 700,000

Incheon (expansion) Kogas 2015 11

Pyeong-Taek (expansion) Kogas 2015 10

Tong-Yeong (expansion) Kogas 2010 2 200,000

Energia Costa Azul Sempra LNG 2008 2 320,000

Mexico Lazaro Cardenas Repsol 2010 2 300,000

Planned New and Expanded LNG Reception Terminals

Country Location/Project Owners/ Start up/ planned Storage

Project Developers start up No. new/ existing Total new/ exisiting

tanks capacity m3

p37-44:LNG 3 06/06/2008 12:56 Page 3

TABLES

Manzanillo CFE 2009

Mexico(contd) Puerto Libertad, Sonora DKRW Energy, Sonora Govt. 2009 2 320,000

Ensenada (offshore GBS) GNL Mar Adentro de Baja

California -Chevron 2009 2 250,000

TAMMSA, Rosarito (o/shr FSRU) Moss Maritime/CEMSA 2008

Dorado HiLoad, Gulf (o/shr FSRU) Tidelands Oil &Gas 2009

Netherlands Gasunie, Royal Vopak, RWE Petroplus

New Zealand North Island Contact Energy, Genesis 2010

Pakistan Karachi Sui Southern Gas Company Ltd. 2010

Philippines Mariveles, Bataan GNPower 2008 2 280,000

Calaga LNG, Manila Bay Batangas Govt. 2015

Poland Baltic PGNiG

Singapore Singapore Energy Authority 2012

El Musel, Gijón, Enagas 2010 2 300,000

Spain Cartagena (expansion) Enagas 2008 1 150,000

Spain - Arinaga, Gran Canaria Gascan, Unelco Endesa 2008

Canary Is. Granadilla, Tenerife Gascan, Unelco Endesa 2008

Sweden Oxelosund Sydkraft Gas (Eon)

Taiwan Tai-chung CPC 2008 3 480,000

Thailand Map Ta Phud PTT 2012

Dragon LNG, Milford Haven BG, Petroplus, Petronas 2008 2 310,000

South Hook, ExxonMobil, Qatar Petroleum, Total 2008 3 465,000

UK Milford Haven 2010 2 310,000

Amlwch, Anglesey Canatxx

Teeside ConocoPhillips

Ukraine Black Sea coast Naftogaz

Blue Ocean Energy (offshore ExxonMobil 2010+

Cove Point (expansion) Dominion 2009 2 320,000

Cameron Sempra LNG 2008 3 480,000

Downeast LNG (Robbinston, Maine) Dean Girdis, Kestrel Energy

USA Freeport Freeport LNG, Cheniere,ConocoPhillips 2008 2 320,000

Neptune LNG Hoegh LNG/Suez LNG 2009

Sabine Pass Cheniere 2008 3 420,000

Bradwood, OR Northern Star

Broadwater Energy, NY (offshore FSRU) TransCanada, Shell 2010 2 350,000

Cabrillo Port, CA (offshore FSRU) BHP Billiton 2010 3 273,000

Calhoun LNG Gulf Coast LNG, Haddington

Port Lavaca, TX Ventures 2009 2 320,000

Clearwater Port, CA (offshore platform) Crystal Energy, Woodside 2010

Corpus Christi, TX Cheniere Energy 2009 3 480,000

Creole Trail, LA Cheniere Energy 2009 4 640,000

Crown Landing, NJ BP 2010 3 450,000

Golden Pass, TX ExxonMobil 2009 5 775,000

HiLoad, Gulf (offshore FSRU) TORP Technology, Golar LNG 2009

Ingleside Energy, TX Occidental Oil & Gas Corp 2011 2 320,000

Jordan Cove, OR Fort Chicago LNG/Energy Projects 2011 2 320,000

Main Pass, Gulf (offshore platform) McMoRan 2009+ 1 145,000

Northeast Gateway (offshore RV) Excelerate 2008

Oregon LNG (Warrenton) 2013 3 480,000

Pascagoula, MS Gulf LNG Energy 2012 2 320,000

Pascagoula, MS (Casotte Landing) Chevron 2012

Pearl Crossing,Gulf (offshore) ExxonMobil 2009 2 250,000

Port Arthur, TX Sempra Energy 2010+ 3 480,000

Port Pelican,Gulf (offshore GBS) Chevron 2010 2 330,000

Providence, RI * Keyspan, BG 2008

Quoddy Bay LNG Quoddy Bay LLC 2011

St. Helens, OR Port Westward LNG 2011

Sparrow Point, Maryland AES CORP. 2011

Vista Del Sol, Ingleside, TX ExxonMobil 2009 3 465,000

Weaver's Cove, Fall River, MA Amerada Hess, Poten & Partners 2010+ 1 200,000

Planned New and Expanded LNG Reception Terminals (continued)

40 • LNG journal • The World’s Leading LNG journal

Country Location/Project Owners/ Start up/ planned Storage

Project Developers start up No. new/ existing Total new/ exisiting

tanks capacity m3

p37-44:LNG 3 06/06/2008 12:56 Page 4

LNG journal • June 2008 • 41

TABLES

Existing Liquefaction plants Country Location/Project Shareholders Start Liquefacton Storage

up No. of capacity No. of Total

trains (nominal) tanks capacity

mtpa m3

Algeria Arzew Sonatrach GL4Z 1964 3 1.1 (1.7) 4 71,000

Bethioua Sonatrach GL1Z 1978 6 7.6 3 300,000

GL2Z 1981 6 8.5 3 300,000

Skikda Sonatrach GL1K 1972 1 1 2 112,000

GL2K 1981 2 2 3 196,000

Karratha Woodside, Shell, BHP, ) 1989 2 Total 7.5 4 260,000

Australia (North West Shelf J.V.) BP, ChevronTexaco, MIMI 1992 1

(Mistubishi/Mitsui) 2004 1 4.5

Darwin (Bayu Undan) ConocoPhillips, Santos, Tepco, 2006 1 3 1 188,000

Tokyo Gas

Brunei Brunei Brunei/Shell/Mitsubishi 1972 5 6.71 3 176,000

Egypt Damietta (SEGAS) Union Fenosa, ENI, EGPC, EGAS 2004 1 5 2 300,000

Idku (Egyptian LNG) EGPC, EGAS, BG, 2005 2 7.2 2 280,000

Gaz de France, Petronas

Equatorial Bioko Island Marathon, GEPetrol 2007 1 3.4 2 272,000

Guinea (Mitsubishi, Marubeni to join)

Indonesia Blang Lancang 1978 3 Total 7 4 508,000

(PT Arun) Pertamina, ExxonMobil, JILCO 1984 2 (13.2)

1986 1

1977 2(A,B) 4 380,000

1983 2 (C,D) 1 127,000

Bontang Pertamina, VICO, JILCO, Total 1989 1 (E) Total 22

(PT Badak) 1993 1 (F)

1997 1 (G)

1999 1 (H)

Libya Marsa el Brega Sirte Oil (NOC/Shell upgrade) 3.2 2 96,000

Bintulu (Malaysia LNG) Petronas, Shell, 1983 3 8.0 4 260,000

Malaysia Bintulu (MLNG Dua) Sarawak Govt, Mitsubishi 1995 3 8.0 1 65,000

Bintulu (MLNG Tiga) Petronas, Shell, Sarawak Govt, 2003 2 6.8 1 120,000

Mitsubishi, Nippon Oil

Nigeria Bonny Island NNPC, Shell, Total, Agip 1999 2 6.4 2 168,400

(Nigeria LNG) 2002 1 3.2 1 84,200

Shell Total, Iberdrola,, Transgas, 2005 2 8.2

Eni, BG and Endesa

Endesa, France's Total and 2008 1 4.0 1 84,200

Royal Dutch Shell

Norway Melkoya Island Statoil, Total, Gaz de France, Norsk 2007 1 4.2 2 280,000

(Snohvit j.v.) Hydro

Oman Oman LNG Oman Govt. , Shell, Total, Korea 2000 2 7.4 2 240,000

LNG, Mitsubishi , Mitsui, Partex

and Itochu

Qalhat LNG Oman Govt. ,Oman LNG Union 2006 1 3.5 2 240,000

Fenosa, Osaka Gas, & Itochu

Ras Laffan (Qatargas) QGPC, ExxonMobil , 1996 3 9.5 4 340,000

Qatar Total, Marubeni, Mitsui

Ras Laffan (RasGas) QGPC, ExxonMobil, Kogas, 1999 2 6.6 3 420,000

Itochu & LNG Japan

Ras Laffan (RasGas II) QGPC, ExxonMobil 2004 1 4.7

Ras Gas II QGPC ExxonMobil 2005 1 4.7

RasGas II - T3 2007 1 4.7

RasGas III - T6 [2] Qatar Petroleum, ExxonMobil 2008 1 7.8

RasGas III -T7 [2] Qatar Petroleum, ExxonMobil 2008 1 7.8

QatarGas III Qatar Petroleum, ConocoPhillips, 2009 1 7.8

Mitsui

BP, BG, Repsol, Suez, NGC 1999 1 3.2 2 204,000

Trinidad Point Fortin BP, BG, Repsol 2002 1 3.2 1 160,000

& Tobago (Atlantic LNG) 2003 1 3.2

2005 1 5.2

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

(UAE) 1994 1 2.5

U.S.A. Kenai - Alaska ConocoPhilips, Marathon Oil 1969 1 1.4 3 108,000

Tables of liquefaction plantsExplanatory Notes� The tables do not include the

following types of LNG facilities :�Liquefaction plants which do not

have a marine terminal for LNG exports, i.e. it excludes most LNG Peakshaving plants and those smaller-scale LNG plants supplying LNG by road tanker or rail.

�Small-scale liquefaction facilities supplying small marine satellite terminals in their own country (such as exist in Norway)

� The existing or planned baseload capacity is given in million tonnes per annum (mtpa)

� Storage capacities are given in m3 liquid (LNG)

� For expansions to existing terminals the numbers given for number of liquefaction trains and their capacity, and for numbers of storage tanks and their capacity, are those for the extra facilities associated with that expansion,not for the total terminal facilities after expansion.

p37-44:LNG 3 06/06/2008 12:56 Page 5

42 • LNG journal • The World’s Leading LNG journal

TABLES

Abu Dhabi Das Island (expansion) Adgas 1

Algeria Skikda Sonatrach 2011 1 4.5

Algeria Arzew (Gassi Touil) Sonatrach/Repsol/Gas Natural 2009 1 3.8

Angola Soyo Sonangol, ChevronTexaco, BP, ExxonMobil, Total 2009 1 5

Australia NWS Venture (Tr.5 expansion) Woodside, Shell, BHP, BP, ChevronTexaco, MIMI 2008 1 4.5

Australia Barrow Island (Gorgon) ChevronTexaco,Shell, ExxonMobil 2011 2 10

Australia Tassie Shoal MEO Australia Ltd./Petrofac Ltd 2011 1 3

Australia Pilbara BHP Petroleum 2012 6

Australia Browse Woodside 2012 10

Australia Greater Sunrise Woodside, Osaka Gas, ConocoPhillips, Shell 2013 1 5.3

Australia Gladstone LNG Santos 2014 1 3.4

Australia Ichthys INPEX, Total 2013 2 6.0

Australia Wheatstone LNG Chevron Corp. 2012 1 5

Bolivia Margarita (Pacific LNG) Repsol, BG and BP 2 7

Brazil Solimoes (Green LNG) Petrobras 2008 1 2.5

Brunei Lumut - Train 6 expansion Brunei LNG 2011 1 5

Egypt Damietta - Train 2 expansion ENI, EGPC, EGAS 2011 1 5

Indonesia Bontang - Tr.I expansion Pertamina, Total, Unocal, VICO 2009 1 3.5

Iran Iran LNG NIOC, BP, Reliance 2012 2 8

Iran Pars LNG NIOC, Total, Petronas 2012 2 8

Iran Persian LNG NIOC, Repsol, Shell 2013 2 10

Iran NIOC LNG NIOC, BG, Enel, Agip 2013 2 9.6

Malaysia Bintulu (exp.) Malaysia LNG, Petronas 1

Mauritania BG

Nigeria Bonny - Train 7 NNPC, Shell, Total, ENI 1

Nigeria Bonny NNPC/ExxonMobil 1 4.8

Nigeria Brass LNG NNPC, Eni, ConocoPhillips, ChevronTexaco 2012 2 10

Nigeria Olokola NNPC, Chevron Nigeria, BG and Shell 2012 4 20

Papua NGuinea PNG LNG Merrill Lynch, InterOil, Pacific LNG 2012 1 4.5

Peru Pampa Melchorita (Camisea LNG) Hunt Oil, SK Corp., Repsol and Marubeni Corp. 2008 1 4.5

Qatar Ras Laffan - expansion (Qatargas III - Train 6) Qatar Petroleum (QGPC),ConocoPhillips 2009 1 7.5

Qatar Ras Laffan - expansion (Qatargas IV - Train 7) QGPC, Shell 2012 1 7.8

Russia Murmansk (Shtockman) Gazprom and partners 2015 2 12

Trinidad Point Fortin -Trains. 5&6. BP, BG, Repsol, NGC 2 10.4

USA Alaska Alaska North Slope

Yemen Bal-Haf (Yemen LNG) Total, Yemen Gas, Hunt Oil, SK Corp, Hyundai 2009 2 6.8

Planned Liquefaction Plants And Expansions

Country Location/Project Project developers Planned No. new new capacity start up trains mtpa

Angola Angola LNG Sonangol, Chevron, BP, ExxonMobil, Total 2012 1 5.0

Indonesia Irian Jaya(Tangguh) BP, MI Berau, CNOOC, Nippon Oil, KG, LNG Japan 2008 2 7.6

Qatar Ras Laffan -exp. QGPC, ExxonMobil Train 4 2008 1 7.8

(Qatargas II) QGPC, ExxonMobil, Total Train 5 2008 1 7.8

Russia Sakhalin (Sakhalin Energy) Gazprom, Shell, Mitsui, Mitsubishi 2008 2 9.6 2 200,000

Liquefaction Plants Under Construction

Country Location/Project Shareholders Start up Liquefacton Storage

No. of capacity No. of tanks Total capacity

trains (nominal) mtpa m3

p37-44:LNG 3 06/06/2008 12:56 Page 6

Ahmed Shehata Production ManagerEGYPTIAN LNG Egypt

Abdelkader Haouari Expansion Start-up ManagerQATARGAS Qatar

David MaocecLNG Project LeaderGAZ DE FRANCE France

Fortunato Donato CostantinoHead of LNGOMV

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