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 latest events, company and 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 and John Kennedy 31 World Carrier Fleet: More new-builds commissioned 38 Tables of liquefaction plants and LNG import terminals worldwide June 2008 44 pages essential LNG news! Australia increases output and expands LNG perspectives Australia’s LNG exports have gradually expanded since the first shipments from the North West Shelf in 1989. The country is now on track, along with Nigeria, to be the world’s main LNG producer 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 reserves According 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
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Transcript
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
No part of this publication may bereproduced or stored in any form by anymechanical, electronic, photocopying,recording or other means without theprior written consent of the publisher.Whilst the information and articles inLNG journal are published in good faithand every effort is made to checkaccuracy, readers should verify facts andstatements direct with official sourcesbefore acting on them as the publishercan accept no responsibility in thisrespect. Any opinions expressed in thismagazine should not be construed asthose of the publisher.
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.
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?
LNG journal • June 2008 • 9
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p1-14:LNG 3 06/06/2008 11:47 Page 9
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:[email protected]
David Haynes, is Advantica’s Principal LNGConsultant. Email:[email protected]
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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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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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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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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
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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
Subscribe now andget 4 issues free!*
AND -20% till 30th July**new subscribers only, terms and conditions apply*
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 [email protected]
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
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
David MaocecLNG Project LeaderGAZ DE FRANCE France
Fortunato Donato CostantinoHead of LNGOMV
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