An Economic Analysis of Floating Liquefied Natural Gas (FLNG)
by
Phillip Christian Marmolejo
Submitted to the
Department of Mechanical Engineering
in Partial Fulfillment of the Requirements for the Degree of
Bachelor of Science in Mechanical Engineering
at the
MASSACHUSETTS INSTITUTE
OF TECHNOLOGY
Massachusetts Institute of Technology
June 2014
JUL 3 0 2014
LIBRARIES
2014 Phillip Marmolejo. All rights reserved.
The author hereby grants to MIT permission to reproduce and to distribute publicly paper and
electronic copies of this thesis document in whole or in part in any medium now known or
hereafter created.
Signature redacted
Signature of Author:
Department of Mechanical Engineering
May 9, 2014
Certified by:
C
-Signature redacted
Francis O'Sullivan
Executive Director, Energy Sustainability Challenge, MIT Energy Initiative
Signature redacted
Accepted by:
Anette Hosoi
Professor of Mechanical Engineering
Undergraduate Officer
2
An Economic Analysis of Floating Liquefied Natural Gas (FLNG)
by
Phillip Christian Marmolejo
Submitted to the Department of Mechanical Engineering
on May 9, 2014 in Partial Fulfillment of the
Requirements for the Degree of
Bachelor of Science in Mechanical Engineering
ABSTRACT
This report includes a discussion of the potential production of stranded natural gas reserves
through the implementation of Floating Liquefied Natural Gas (FLNG) in a world of growing
energy demand followed by an analysis of the technology's economic feasibility. The economic
analysis aims to use production and expense estimates related to Shell's Prelude FLNG project in
order to determine the project's FOB breakeven price. The net present value (NPV) of the
project's discounted future cash flows is used to determine this breakeven price.
The results of the economic analysis revealed the FOB breakeven price of Shell's Prelude project
to be $8.16 per MMBTU, a reasonable calculation given current breakeven price estimates for
similar projects in the area. Even with a 15% error band in Shell's production estimates, the
breakeven price remained in the range of $8-$9 per MMBTU. However, when the production of
lean natural gas was considered, the breakeven price exceeded $12 per MMBTU, a price that is,
based upon current forecasts, too high to warrant consideration of such a project.
It was found that with production incentives, such as LPG and condensate, the current FLNG
design can prove to be economically successful, given the current LNG price forecasts.
However, for the production of stranded reserves lacking these production incentives, a separate
lean FLNG design should be considered.
Thesis Supervisor: Francis O'Sullivan
Tile: Executive Director, Energy Sustainability Challenge, MIT Energy Initiative
3
Table of Contents
Abstract
3
Table of Contents
4
List of Figures
6
List of Tables
7
1. Introduction
8
1.1 Natural Gas: An Overview
10
1.1.1 Origin of Natural Gas
10
1.1.2 Chemical Composition
12
1.1.3 Natural Gas Production
14
1.1.4 Natural Gas Processing and Treatment
19
1.1.5 Natural Gas Uses
22
1.2 Liquefaction of Natural Gas
23
1.2.1 Benefits of Liquefaction
23
1.2.2 Liquefaction Process
24
1.3 LNG Global Market
27
1.3.1 Market Overview
27
1.3.2 Imports/Exports
29
1.3.3 LNG Pricing
31
2. Challenge in the Natural Gas Industry: Stranded Gas
2.1 Stranded Gas
33
33
2.1.1 Introduction to Stranded Gas
33
2.1.2 Geographical Distribution of Economically Stranded Gas
33
3. FLNG: A Potential Solution
34
3.1 Introduction to FLNG
34
3.2 Unlocking Stranded Gas
35
3.3 Design Challenges
37
3.4 Current State of Technology
38
4. Shell Prelude FLNG Project
4.1 Prelude: An Introduction
4.1.1 Early Beginnings of Prelude
40
40
40
4
4.1.2 Project Overview
41
4.2 Meeting the Design Challenge
42
4.2.1 Addressing Sizing Constraints
43
4.2.2 Addressing Operational Challenges
43
4.2.3 Ensuring Operational Safety
45
4.3 Economic Analysis
46
4.3.1 Analysis Overview
46
4.3.2 Project Lifespan
47
4.3.3 Project Revenue
48
4.3.4 Project Costs
51
4.3.5 Discount Rate
54
4.3.6 Depreciation Scheduling
55
4.3.7 Amortization
57
4.3.8 FOB Breakeven Price Calculation
59
4.3.9 Addressing Model Limitations
61
5. Conclusion
62
5.1 Discussion of FOB Breakeven Price Results
62
5.2 Advancing FLNG Technology
63
5.3 Prelude's Potential Impact
65
6. Bibliography
66
5
List of Figures
Figure 1:
Theoretical diagram of the earth's cross-section
12
Figure 2:
Typical molar composition of natural gas mixtures
13
Figure 3:
Artistic depiction of the end result of a drilling process
16
Figure 4:
Flow diagram of a typical natural gas processing unit
20
Figure 5:
Process flow diagram of the C3-MR process
27
Figure 6:
Global LNG trends from 1990 to 2012
28
Figure 7:
Graph of natural gas imports share of consumption
29
Figure 8:
Major natural gas trade routes as of the year 2012
30
Figure 9:
Estimated LNG Prices for November 2013, by region
32
Figure 10:
Conceptual design for Shell's Prelude FLNG facility
42
Figure 11:
Subsea components of Shell's Prelude facility design
46
Figure 12:
General graph of Arps Decline Curves
50
Figure 13:
Operational cost estimates for onshore LNG plants
53
Figure 14:
Depreciation schedule used in NPV analysis
57
Figure 15:
Amortization schedule used in the NPV analysis
59
Figure 16:
Predictions of JKM and Henry Hub prices by Rice World Gas Trade Model
63
6
List of Tables
TABLE 1:
Fixed cost fees relevant to Prelude FLNG project
52
TABLE 2:
FOB breakeven price results
61
7
1. Introduction
The future of the world's energy supply has grown to become a highly discussed topic over
the last decade for several converging reasons. According to an estimate conducted by the
United Nations in 2012, the world's population is expected to grow to 9.5 billion by the year
2050, a 34% increase from the current population [1]. Additionally, the Organisation for
Economic Co-operation and Development (OECD) predicts that by the year 2030, developing
countries will grow to account for nearly 60% of the world GDP, which is expected to bring
about a higher standard of living in those countries [2]. Together, these two predictions foretell
of a more heavily populated world with a significantly higher standard of living for many of
those in developing countries. Such a future would demand a substantial increase in energy
consumption, suggesting that the growth in world energy consumption which has been
recorded over the previous decades is not likely to end soon.
In order to properly plan to meet the energy demands of the future, several factors must be
taken into consideration and several parties must do their part. The most apparent factor is
supply. Energy producers must provide an adequate supply quantity at an acceptable price to
allow for a growing demand. But as the future energy consumption increases, currently tapped
fossil fuel reservoirs will begin to diminish at an accelerating rate, forcing some to run dry by
2050. In order to continue to meet a growing demand, energy producers must eventually begin
to tap into new reservoirs. Therefore, energy companies must plan to meet the challenge of
discovering new, producible plays and/or developing new strategies for making previously
deemed uneconomic fields profitable.
8
The second factor is efficiency, a factor which helps determine the definition of an adequate
supply. If the efficiencies of commonly used consumer goods are increased, the amount of
energy demanded for a given standard of living will decrease. Therefore, producers of
consumer goods must work to increase the energy efficiency of their goods to help restrain the
true increase in energy consumption and to ease the supply efforts by energy companies.
However, in the modern world it is no longer adequate to ensure that the energy demand is
met by supply at a reasonable price. The third factor that must be also considered is carbon
emission output of the world's future energy portfolio. As the use of fossil fuels increases to
meet the future energy demand, so will the associated carbon emissions. Over time, the carbon
emissions accumulate in the atmosphere, producing a greenhouse effect which, in turn, results
in climate change. In order to provide a safe environment for the future population, measures
must be taken to sequester atmospheric greenhouse gases and/or to reduce the carbon
emissions of the future world energy portfolio.
As it appears, planning to meet the future energy demand proves to be a large and difficult
task with no clear solution. Research and developments from various sectors of the energy
industry must come together if the challenge is to be met properly. Such a task is beyond the
scope of this particular analysis. Rather, this report aims to analyze a single development which
may potentially play a role in helping to take on this energy challenge: floating liquefied natural
gas (FLNG). Natural gas is a likely candidate as a leading source of energy in the world's future
energy portfolio since it is a versatile fuel and the cleanest burning fossil fuel. As energy
consumption rises and the need to produce from additional natural gas reservoirs grows, FLNG
9
could play the role of making previously stranded offshore natural gas fields economical, thus
increasing the number of attainable reserves. The first step to meeting the future's energy
challenge is a proper analysis of the various options today.
1.1
Natural Gas: An Overview
1.1.1
Origin of Natural Gas
Natural gas is a term that is used to describe a naturally occurring hydrocarbon gas mixture
that can be found captured within underground earth formations. It is generally accepted that
today's natural gas reserves originated from organic debris, or kerogen, buried with inorganic
sediments millions of years ago. The proposed theory claims that the kerogen and sediment
mixture first became buried under the earth's surface, after which it reached increasingly
greater depths due to natural shifts of the earth's formations. As the depth of the buried
composition increased, so did the local hydrostatic pressure and temperature. Once the organic
kerogen and inorganic sediments reached great enough depths, the high local hydrostatic
pressure and temperature altered the kerogen, producing the fossil fuels that energy
companies can produce today, and solidified the inorganic sediments around it, producing
sedimentary rock formations, such as shale, from which the fossil fuels are derived [3].
Since natural gas is found in gaseous form under standard atmospheric conditions, it is
much less dense than the rock formations in which it is contained, otherwise known as the
source rock. Therefore, it will naturally tend to travel vertically from the source rock and toward
the earth's surface. The gas will continue travelling vertically through the denser rock and
10
eventually reach the surface of the earth if the formations above the source rock have a
sufficient porosity to allow the gas to traverse. However, if the gas encounters an impermeable
rock formation while ascending from the source rock, it will accumulate and settle within the
porous rock below the impermeable formation, thus creating a fossil fuel reservoir. The
impermeable rock that traps and contains the natural gas is referred to as the cap rock and the
porous rock in which the fossil fuel accumulates is referred to as the reservoir rock.
Generally, there are three main gas reservoir categories: associated, non-associated, and
unconventional. Associated gas refers to natural gas found within a reservoir in which both
crude oil and natural gas accumulated together. Most oil reservoirs that do not produce what is
termed extra heavy crude, liquid petroleum with API gravity less than 20, will produce some
amount of natural gas dissolved within the crude oil. Typically, the greater the depth of the
reservoir, the lighter the product, meaning there is a higher ratio of natural gas to crude oil in
the produced solution. Expectedly, non-associated gas refers to natural gas originating from a
reservoir which primarily contains natural gas. These types of reservoirs are generally found at
much greater depths than those which contain associated gas. Lastly, unconventional gas refers
to natural gas that is contained in such a way that it once presented higher levels of production
difficulty in comparison to associated and non-associated natural gas [4]. One such example is
"tight gas", or natural gas trapped within low-permeability formations such as shale. The term
"unconventional" has lost some of its original meaning since the production of shale reservoirs
has become a standard practice in the recent decades through the expanded use of massive
hydraulic fracturing. Figure 1 provides a visual representation of the different types of gas
reservoirs [5].
11
Figure 1: Theoretical diagram of the earth's cross-section
illustrating the main types of gas reservoirs
1.1.2
Chemical Composition
As previously stated, natural gas is a term used to describe a hydrocarbon gas mixture.
However, its exact chemical composition is not strictly defined and may vary from reservoir to
reservoir. With that being said, the gas mixture does tend to have a typical composition.
Natural gas is typically composed primarily of methane (CH4), which can account for over 90%
)
of the molar composition of dry, non-associated natural gas. Ethane (C 2 H 6 ) and propane (C 3H 8
12
are the next most abundant fuels by molar percentage, while heavier fuels such as butane
(C 4 H1 0 ) and pentane (C 5 H 1 2 ) are less abundant but still common. If a gas product contains
significant amounts of hydrocarbons as heavy as or heavier than pentane, which are liquid at
standard atmospheric conditions, the mixture is referred to as a "wet" gas. Otherwise, the gas
is referred to as a "dry" gas, which is not meant to signify the absence of water vapor in the
produced gas. The specific composition of a produced gas must be known in order to determine
its actual chemical characteristics and an abundance of certain components such as natural gas
liquids may warrant processing. But in industry, it is standard to estimate the calorific value of
an unknown natural gas composition to be approximately 38.1 MJ/m
3
[4]. Figure 2 details the
typical molar composition of natural gas mixtures from both associated and non-associated
reserves [6].
15.0
400.0
100.0
Figure 2: Typical molar composition of natural gas mixtures,
both associated and non-associated
13
1.1.3
Natural Gas Production
The production of natural gas varies depending upon the type of natural gas reservoir
(associated or non-associated), the way in which the reserve is contained (conventional or
unconventional), and the location in which the reservoir is located (onshore or offshore). This
report will first focus on the production of associated gas reservoirs before shifting the
discussion to the production of non-associated reservoirs. In associated gas reservoirs, the
associated natural gas is produced together with the reservoir's crude oil. Once an associated
reservoir is discovered, verified to be economically producible, and sufficiently understood by
the producing company, the production preparations can begin.
In the first step toward preparing the site for production, the producing company must
drill the well from which they will produce. In onshore production, the drilling process begins by
erecting the drilling rig, from which the rest of the drilling process is to be completed, at the
surface of the future wellbore. The producing company will then begin drilling the well. The
drilling rig is used to rotate the drilling string, a length of drilling pipe that can be extended as
the wellbore grows deeper, with a drill bit attached to the end in order to penetrate the
surface. The entire depth of the wellbore is not drilled in one step. Rather, the drilling process
begins with the drilling of a starter hole of significantly lesser depth. While drilling the starter
hole and other subsequent holes, drilling fluid, a varying mixture of fluids, solids, and chemicals,
is circulated through the head of the drill bit and toward the surface in order to float rock
cuttings to the surface, prevent overheating of the drill bit, maintain the structural integrity of
the wellbore, and prevent fluids from entering the wellbore from the walls of the well. Once
14
the starter hole has been drilled, it is lined with casing, typically a hollow steel pipe of a lesser
diameter than the wellbore, and cement is pumped around the outer diameter of the casing
using a bottom plug. The cemented casing serves the purpose of preventing an inward collapse
of the drilled wellbore as well as further isolating shallower depths from the future
hydrocarbon production. The shallow drilling and casing process is then repeated two to four
more times, each at a greater depth and using a smaller drill bit and casing diameter, until the
final depth is reached. Once the final depth has been reached, which can be signaled by oil
sands found in the rock cuttings, and the production casing has been set, the drilling process is
complete. Figure 3 provides a visual of the final result of the several stages of drilling. In the
visual provided by Figure 3, three intermediate levels of casing were cemented [7].
15
Figure 3: Artistic depiction of the end result of a
drilling process
The next step toward production is the completion process. The purpose of the
completion process is to connect the drilled wellbore to the reservoir and finalize the well for
production. This process begins by perforating the production casing to allow for the flow of
hydrocarbons. A perforation gun blasts holes through the production casing at the depth of the
reservoir. Once the perforations have been made, fracturing fluids or acids may be pumped
into the reservoir rock to optimize hydrocarbon flow from it. With the reservoir rock prepared,
the casing above the perforations is packed and the production tubing, a pipe of smaller
diameter than the production casing, is installed. The production tubing serves the purpose of
isolating the casing from the produced fluids to prevent its damage. If the tubing is damaged, it
16
can be replaced since, unlike the casing, it is not cemented in place [7]. With the tubing in
place, the preparation for production is complete. Many wells tend to have a higher enough
reservoir pressure to produce hydrocarbons to the surface naturally; however, if the reservoir
pressure is not sufficient production may require forms of artificial lifts. A company's
completion team may oversee the production process itself for a few weeks to ensure that the
well is producing and there isn't a need to recomplete the well. Once this is verified, the
completion process is complete and the well is transitioned to the production team.
Once an associated well is producing its hydrocarbon and water mixture, the last step of
the process is extracting the useful products through separation. This separation occurs
naturally by the effect of gravity and the varying densities of the fluids; however, additional
heat is added during part of the process to accelerate the settling times. The produced fluid is
passed through several separation stages where natural gas, being the least dense fluid in the
mixture, flows through the exit piping located at the top of the vessel, water, being the densest
fluid in the mixture, flows through the exit piping located at the bottom of the vessel, and crude
oil, which is less dense than water but denser than natural gas, flows through the exit piping
located somewhere in between. Once completely separated, the gas has successfully been
produced.
Non-associated gas reservoirs are produced in very much the same manner as
associated gas reservoirs. However, once the production stage is reached, there isn't any need
for extensive density separation procedures. This slightly eases the production process, but the
produced natural gas still needs to be processed before it can be considered a finished good
17
prepared for final sale for use. The production of offshore reservoirs may also be similar to that
of on-shore associated gas reservoirs, depending on the particular type of well; however, there
are also some key distinctions between offshore and on-shore wells.
In the case of offshore drilling, a typical on-shore drilling rig is replaced by a mobile
offshore drilling unit (MODU), which is a vague term that covers several types of offshore
drilling units. Modern MODUs can further be categorized as jackups, semisubmersibles, or
drillships. Jackups can only be used for shallow water drilling, depths of less than 500 ft., and
consist of a drilling rig which can be situated upon a floating barge. Once situated, the jackup
can then extend its legs and secure them to the sea floor. With the legs secured, the jackup
raises its hull above sea level, to avoid any unnecessary hull motion that may be caused by the
tidal movements, and is ready for operation. Semisubmersibles are drilling units which can be
towed to the drilling location and then kept afloat by the submersion of pontoons. Once in
position, the semisubmersibles are then anchored or kept in position by the means of a
dynamic positioning system such as automated position-correcting propulsion. Semisubmerible
MODUs are often used for deepwater applications, up to depths of 10,000 ft. Lastly, drillships
are typically reserved for depths unattainable by semisubmersibles, ranging from 10,000 ft. to
12,000 ft. They have a drilling rig situated above a hole in the ship's hull, from which the drilling
takes place. Drillships require position stabilization in the form of anchoring as well as dynamic
positioning [8].
Offshore production wells can be either surface wells or subsea wells. Surface
production wells are much like those used in onshore production, featuring production tubing
18
that extends to a production rig at the sea's surface. Subsea wells, however, are rather
different. In the case of subsea wells, the production equipment that is normally found at the
surface of the well location is instead installed on the sea floor. This practice brings with it the
challenge of managing the increased hydrostatic pressures on the production vessels without
any direct access for maintenance. The draw of subsea wells lies in the ability to produce
several well locations using only a single supporting facility. This advantage is utilized by
Floating Liquefied Natural Gas facilities, as will be explained in further detail later in this report.
1.1.4
Natural Gas Processingand Treatment
Once natural gas has been extracted, it needs to be treated and processed in order to
produce a finished product which can then be sold on the market. The extent to which the
extracted natural gas must be treated and processed depends entirely upon the composition of
the gas. Natural gas processing most greatly focuses on addressing exceedingly high quantities
of water (in the form of either a vapor or a precipitate), heavier hydrocarbons (such as propane
and butane), and acid gasses (such as carbon dioxide and hydrogen sulfide). The higher the gas
mixture's molar ratio of these components to methane means the greater the need for
treatment and processing. Figure 4 provides a visual of the natural gas process flow diagram
[9].
19
Welihead
producing raw
Gaes/liquid geparator
s
sweetening
Dehydration
separate methane
from other hydrocarbons
Figure 4: Flow diagram of a typical natural
gas processing unit
The first undesirable that is processed out of the natural gas mixture is acid gas. Acid gas
is a generic name which refers to gases, such as carbon dioxide and hydrogen sulfide, which
have an acidic reaction and may corrode the piping and valve components of a system. The
removal of acid gas from the natural gas mixture is important for the avoidance of degradation
in pipelines that are not protected against corrosion. Acid gas is most commonly removed
through the implementation of an amine gas treating process. In the absorption vessel of this
particular process, a downstream feed of a lean amine solution intersects the upstream feed of
the original natural gas mixture. When the two streams intersect, the amine solution absorbs
the acid gas and the relatively high density combined mixture exits the absorption vessel from
its low point while the treated natural gas mixture exits the absorption vessel from its high
20
point. The used amine solution then enters the regeneration stage of the process, where some
of the lean amine is recovered for reuse in the process [10].
The second undesirable that is processed from the original natural gas mixture is water,
which is the most prevalent undesirable component found in typical natural gas compositions
and may exist in the form of condensate or vapor. Water in the natural gas mixture is
undesirable for several reasons. It can combine with hydrocarbons under certain conditions to
form hydrates which can plug lines and valves, collect as condensate in low points of piping to
reduce a line's capacity, act as condensate to accelerate corrosion within a line or vessel, or
freeze within processes to plug lines and valves. Therefore, it is necessary to dehydrate a
natural gas mixture prior to distribution. The most commonly used dehydration process is
glycol dehydration, which is similar to the amine gas treating process. In this process, lean
glycol is fed upstream through a vessel known as a glycol contactor, in which the upstream
glycol feed insects the downstream natural gas stream containing water vapor. The glycol
removes water from the natural gas stream through absorption, and the water-glycol mixture
exits the bottom of the vessel, as its density is higher than that of the treated natural gas
stream. Glycol dehydration is the most common natural gas dehydration process since it is
relatively cheap, with most of the costs deriving from operating the glycol regeneration vessels
and replacing any glycol which cannot be regenerated [11].
Extracting natural gas liquids from the natural gas mixture may prove to be beneficial
under certain conditions. If there is an abundance of propane and heavier hydrocarbons, these
components may condense in pipelines through cooling or compression and then accumulate
21
at low points in the pipeline, thus reducing a line's capacity. Additionally, the removal of some
accompanying hydrocarbons allows for their independent sale, which could add to the
economic value of the natural gas mixture as a whole. If either or both of these conditions hold
true, accompanying hydrocarbons will be processed out of the original mixture. Excessive
amounts of natural gas liquids are most likely to occur in gas mixtures originating from
associated gas reservoirs; therefore, these natural gas mixtures are more likely to require
hydrocarbon extraction in order to reach a marketable quality. The popular method for
hydrocarbon extraction is the combination of expansion and fractionating distillation. In the
expansion stage, the natural gas mixture is fed through a turbo-expanded in order to drop the
temperature of the mixture. The low-temperature natural gas mixture is then fed through a
fractionating column, where the individual components of the mixture are separated based
upon their volatility. This process separates the hydrocarbons for sale or further processing [3].
11.5
Natural Gas Uses
Once natural gas is treated and processed to a marketable quality, it can be sold for use
in several applications. According to the 2013 Key World Energy Statistics report provided by
the International Energy Agency (IEA), natural gas directly accounted for 1,380 million tonnes of
oil equivalent (Mtoe), or 15.5%, of the 2011 world energy consumption. The world's direct
natural gas consumption was distributed amongst industry (36.7%), transportation (6.7%), nonenergy (12.4%), and other (44.2%) uses [12]. In industry, natural gas can serve many different
applications, as it can be directly burned to provide the source of heat or mechanical power
required by a given task. Natural gas has begun to make its way into the transportation sector
in the form of compressed natural gas (CNG), fueling specially designed engines which allow for
22
its use. Non-energy uses for natural gas come in the form of the manufacturing of products or
chemicals for which natural gas as a byproduct. Some of these products include fertilizers,
antifreeze, and methanol. Other direct uses for natural gas may come in the form of heating
and lighting in residential and commercial buildings [12].
Aside from the direct uses for natural gas detailed above, natural gas can also be used
indirectly by way of electricity generation. According to the IEA report, natural gas generated
21.9%, or approximately 484.5 TW-h, of the world's electricity in 2011. Natural gas generates
electricity through its use in gas-fired power plants. These plants use the heat generated from
the combustion of natural gas and air in order to run a steam turbine coupled with a generator,
thus converting some of the energy stored within natural gas to electricity. The generated
electricity provides a more mobile and versatile form of energy for many applications as it is
better integrated than natural gas is.
1.2
Uquefaction of Natural Gas
1.2.1
Benefits ofLiquefaction
Liquefied natural gas, or LNG, is the condensed liquid form of the naturally gaseous,
methane-based fossil fuel. The origins of natural gas liquefaction date back to the
19 th
century,
when Michael Faraday attempted to determine the vapor pressure of several gases including
methane. Although he eventually failed in liquefying methane, his research paved the way for
the efforts of future scientists in better understanding liquefaction [4]. At atmospheric
pressure, natural gas condenses into its liquid form at approximately -162*C, or about -260*F.
LNG is colorless, odorless, non-corrosive, and non-toxic. It also has a volume ratio of about
23
1:600 when compared to gaseous natural gas at atmospheric conditions [4]. Therefore, natural
gas is about 600 times more energy dense when liquefied. This fact illustrates the main benefit
of LNG; it requires less space for storage and transportation when compared to gaseous natural
gas.
Natural gas, like any other fossil fuel, is limited in supply and unevenly distributed across
the globe. If the supply side produces more than is necessary at a given time, the excess natural
gas must be stored for future use in order to avoid an unnecessary loss of a limited resource. If
a certain location demands natural gas for its own consumption but lacks the means to meet its
own demand, then natural gas must be transported to the location from an exporting location.
Both of these acts, storing and transporting natural gas, come at a cost which is proportional to
the density of the natural gas. Therefore, LNG can provide a reduced cost for natural gas
storage and transportation if it occurs on a scale such that the combined cost of liquefaction,
regasification, and added containment requirements is not greater than the savings from the
density increase. Today, natural gas is transported either as LNG on ships with special cryogenic
vessels or as CNG within natural gas pipelines. LNG transportation is more convenient where no
natural gas pipeline exists and the distance to be travelled is relatively far.
1.2.2
LiquefactionProcess
A raw natural gas mixture must undergo several processes in an LNG train before it can
be stored and transported as LNG. The early stages of the LNG process ensure that the natural
gas mixture is free of components hazardous to the LNG plant or the storage and
transportation vessels. The first stage of this process is the treatment of acid gas within the gas
24
mixture. Acid gases must be removed prior to liquefaction to safeguard the LNG facility and
storage containers from acidic corrosion. This treatment stage is carried out in an absorption
vessel using an amine gas treating process. An outline of treating gases with an amine solution
is provided in Section 1.1.4 Natural Gas Processing and Treatment. Once the acid gas has been
removed from the mixture, the rest of the mixture must be dehydrated in order to prevent
hydrate formation and condensation downstream. The dehydration process is carried out in a
glycol contactor using a glycol dehydration process. The glycol dehydration process is further
detailed in Section 1.1.4 Natural Gas Processing and Treatment. The last of the processing steps
aims to distill the methane from the remaining natural gas mixture. This stage of the process is
carried out in a fractionating distillation column, which separates the components of the
natural gas mixture depending upon volatility. With the methane ratio of the natural gas
mixture at an acceptable level, typically 9:1 or greater, the natural gas is ready for liquefaction.
There are several proposed and practiced methods for the liquefaction of natural gas;
however the propane-precooled mixed refrigerant (C3-MR) cycle is used in many of today's
operating LNG plants, utilized in more than 80% of all LNG operations [13]. This process
achieves liquefaction in a single cycle using a multi-component refrigerant which condenses
and evaporates over a wide range temperature range. The natural gas is first precooled to a
temperature of about -30'C using cooling water condensed propane as a refrigerant. This step
is performed to ensure that any NGLs that remain in the mixture can be removed at the low
point of a scrub column and used as a makeup feed for the mixed refrigerant or sold as NGLs.
The precooled natural gas is then fed into the cryogenic heat exchanger where it is to be
condensed and subcooled. Within the cryogenic heat exchanger, the precooled natural gas and
25
mixed refrigerant are cooled and condensed as they flow in separate spiral tubing toward the
top of the vessel. The LNG leaves the cryogenic heat exchanger and is subsequently flashed to
the pressure of the storage tanks, while the mixed refrigerant exits the heat exchanger and is
fed through throttle valves to reduce its pressure. Following the pressure reduction, the mixed
refrigerant is sent back into the cryogenic heat exchanger, this time flowing outside of the spiral
tubing, where it is vaporized, providing added refrigeration to the fluids within the spiral tubing.
Finally, the mixed refrigeration vapor exits from the low point of the cryogenic heat exchanger
and is recompressed and precooled for reuse. The C3-MR process is widely used due to its high
efficiency when compared to a pure refrigeration cycle or a pure mixed refrigeration cycle.
Figure 5 provides a process flow diagram of the C3-MR process. Once the natural gas is
successfully liquefied it can be moved to nearby storage facilities and later loaded for
transportation [14].
26
P
prom
HIP di w
LNG
;-
Tm
c~sr
MP
ch r-
prqpme
lip CNNer LP
prqwwn
ProMn
dhew
rewoop
k-
dblHer
Figure 5: Process flow diagram of the C3MR process
1.3
1.3.1
LNG Global Market
Market Overview
The first LNG plant was built in West Virginia in the year 1912; however, it was not until
the year 1959 that the development of the first LNG tanker would pave the way for the
international trade of LNG [15]. The world LNG market has grown considerably since then,
fueled by an increase in the required infrastructure, such as LNG capacity and the number of
corresponding regasification plants and LNG tankers, and a growing demand for natural gas in
countries which lack enough of the resource domestically. Global LNG trade has more than
doubled since the start of the
2 1 st
century. According to the International Gas Union (IGU), LNG
trade in 2012 measured in at 237.7 million tonnes (MT), more than twice that of 2000 [16]. This
trade volume accounts for 9% of the total global trade of natural gas. By the end of 2012, the
27
worldwide liquefaction capacity had grown to 280.9 MT per annum (MTPA), the global
regasification capacity had reached 649 MTPA, and the number of LNG tankers had consisted of
362 vessels with a combined capacity of 54 billion cubic meters (bcm). Only one exporting
country had put a hold on its trade, due to political unrest, while the number of importing
markets continued its growth. Figure 6 provides a chart of the trends in LNG trade from the
year 1990 to 2012 [16].
700
..
500
-
Global Regasification Capacity
.....
- 25
No.ofLNG Exporting Countries (right axis)
-
.
600
30
oVOlume of LNG Trade
- 20
---- No.ofLNG Importing Countries (right axis)
300
_-
00-
0000ow,15
._
10
-----_-_----
100
0
15
d
200
z
-5
o)
CD0
0r
C
4M
M~0 0 D0) 0)
M-4M
0 C>C1
Coo 0000008080000)
Figure 6: Global LNG trends from 1990 to
2012
Looking forward, global LNG flows are expected to increase, as construction on new
liquefaction plants, regasification facilities, and shipping vessels is underway. As of mid-2013,
30 LNG trains with a total expected capacity of 110 MTPA were in development, three countries
which had not previously imported LNG had regasification projects underway, and 96 vessels
with a combined capacity of 16 million cubic meters were ordered [16]. The projected increases
in global LNG trade reflect the expectation that the demand for natural gas in current and
future LNG importing countries will increase and that pipeline construction into these countries
will not provide the supply to meet this demand increase. According to British Petroleum's (BP)
Energy Outlook 2035 report, LNG trade is predicted to, in the long-term, increase relative to gas
28
trade by pipeline. This expectation is illustrated in Figure 7, which shows the past and predicted
share of consumption for natural gas imports [17].
40%
Total
30%
Pipeline
20%
LNG
-
10%
0%
1990
2005
2020
2035
Figure 7: Graph of natural gas imports
share of consumption
1.3.2
Imports/Exports
Many countries involved in international LNG trade generally only have the
infrastructure to either receive imports or ship exports, although some countries do partake in
re-exporting LNG. The net exporting countries are typically those which have an abundance of
produced natural gas as well as a customer with the means to accept LNG imports rather than
pipeline imports, while the net importing countries are those which wish to import LNG to meet
a discrepancy between their domestic natural gas reserves and their natural gas demand. These
trades have historically been based upon long-term contracts signed by an importing facility
and its corresponding LNG supplier. A trade contract can detail the party responsible for the
transportation of the supply as well as pricing agreements and should be signed before a
29
proposed LNG plant is to be deemed economically feasible. Figure 8 is provided by BP and
provides a diagram of the major natural gas trade routes as of the year 2012. The routes with
blue arrows indicate LNG trade routes [17].
Natural gas major trade movements 2012
Trade laws woddwid.Oi on cubicmeptr
INatura
22 trademnoy
Uent2 11
Ae
S'A#tAmr
** usnAd
0
4
*
IS
Europ &.Eurnsia
hviddle Esd
Meico
Asi. Pod
L4
NG
Figure 8: Major natural gas trade routes as
of the year 2012
As of 2012, there were 17 LNG exporting countries; however, there was a wide range in
the exports of individual countries. The top four exporting countries (Qatar, Malaysia, Australia,
and Nigeria) accounted for more than 60% of the world's exports, while the bottom nine
accounted for less than 25%. Countries from Europe and the Americas have yet to become big
players in the LNG exporting business, but there are expectations that exports from the United
States will heavily increase [16]. BP's 2035 Energy Outlook report predicts that by the year
30
2035, all of the natural gas exports from the United States will come in the form of LNG [17]. On
the demand side, there were 28 importing countries by the end of 2012. Similar to the
exporting countries, only a few of the importing countries accounted for a significant portion of
the global LNG imports. Japan is the world's top LNG importer, bringing in 180 MT in the year
2012 [16]. This is due to the fact that Japan relies solely on imports to supply its natural gas
demand, a demand that has increased following the nuclear power plant disaster in Fukushima.
Much of the LNG imports are focused in the European and Asia Pacific regions, since they lack
the domestic resources to sufficiently meet their natural gas demand.
1.3.3
LNG Pricing
Unlike the price of oil, LNG prices can vary greatly depending upon the importing region.
The variance in pricing amongst regions is attributed to the fact that LNG is not yet a globally
traded commodity. Instead, most of the international LNG trade relies upon the signing of longterm contracts between buyers. In the negotiations of these long-term contracts, the importing
party and the exporting party determine the pricing method that will be used for the LNG
supply. An LNG pricing method is typically a price formula which indexes a global fuel-related
commodity, a collection of global fuel-related commodities, or the market [18]. LNG prices are
commonly benchmarked by the Henry Hub spot price (for North American imports), the United
Kingdom National Balancing Point, or UK NBP, price (for European imports), or the Japan LNG
price (for Asia Pacific imports). The high variance in regional LNG prices is visible in Figure 9
[19].
31
World LNG Estimated November 2013 Landed Prices
Figure 9: Estimated LNG Prices for
November 2013, by region
Although long-term contracts dominate the international LNG trade, the spot and short-
term LNG market is emerging, growing to account for 31% of the global LNG trade in 2012. This
market has experienced growth due to a growing number of importing countries and available
trading vessels, which allow for more trading options, and the arbitrage potential which arises
from regional price discrepancies. A continued growth of the spot and short-term LNG market
will move LNG pricing toward commoditization [16].
32
2. Challenge in the Natural Gas Industry: Stranded Gas
2.1 Stranded Gas
2.1.1
Introductionto Stranded Gas
Stranded gas is a term that is used to refer to a discovered natural gas reserve which is
not considered to be producible. Every reserve of stranded gas can then fall into one of two
categories, each with a different cause for being considered unproducible. The first category is
physically stranded gas. Physically stranded gas reserves are those which cannot be produced
with current technology. Examples of physically stranded reserves include those which are
located at currently unreachable depths and those which are located in areas with harsh
climates [20]. In order to move these reserves from a stranded state to one of production,
progress must be made to improve the production capabilities of the industry.
The second category is economically stranded gas. These gas reserves are recoverable,
but not considered economical since they are deemed to be too far from a market, making the
construction of a gas pipeline too difficult and costly. In order to monetize economically
stranded natural gas reserves, a nearer market must be found or the midstream costs to an
existing market must be reduced to a reasonable level. Moving forward, one of the biggest
challenges posed to natural gas producers is discovering ways in which to bring these currently
stranded gases to market [21]. This means they must discover new methods to increase their
production capabilities and/or reduce their cost of long-distance supply transportation.
2.1.2
Geographical Distributionof EconomicallyStranded Gas
A 2011 United States Geological Survey (USGS) report estimates there to be a total of 2,612
trillion cubic feet in stranded gas reserves outside of North America [22]. Russia, with most of
33
its stranded gas located in Siberia where no pipelines currently exist, contains 33% of these
estimated reserves. In order to monetize some of these fields, pipelines connecting to and
extending from Russia's current lines are under construction or consideration. The Southeast
Asia & Oceania region contains the next largest portion of stranded gas reserves with 17%. A
great majority of these fields are located offshore, in the area of Brunei, Indonesia, and
Malaysia. Other notable regions of stranded gas include the Middle East, Central Asia, and
Africa. In total, 70% of the estimated stranded gas reserves from this report are located
offshore.
3. FLNG: A Potential Solution
3.1
Introduction to FLNG
Floating liquefied natural gas (FLNG) refers to an offshore processing facility designed to
liquefy a natural gas feedstock originating from nearby offshore reserves for the purpose of
transportation to a demanding natural gas market. Although no FLNG projects have ever begun
operation, the original concept of FLNG dates back to the 1970s, during the early years of
international LNG trade [13]. Since then, researchers have studied the most optimal
requirements for a potential FLNG facility and developed several different concept designs. The
currently favored design is that of a compact floating facility complete with a hull and deck
which would be anchored in place at the location of production. This FLNG facility design would
act as the hub of production operations, similar to a multi-well offshore production platform,
collecting natural gas product from multiple subsea wells. It would then process, liquefy, and
store the produced fuel for periodic offloading onto LNG tankers. The number of necessary
34
facility components and the process outline may vary depending on site specifics, such as the
composition of the produced gas and any local environmental hazards, as well as company
preferences.
Unlike standard LNG facilities, FLNG allows natural gas deriving from deep water wells to
be treated, processed, and liquefied at its production location. This novelty eliminates the need
for the construction of transmission pipelines to shore, which become more costly the longer
the required length. Instead, local liquefaction allows for the direct distribution of the natural
gas to demanding markets via LNG tankers, which offer an increased reach to far-off markets
when compared to pipeline transported natural gas. Therefore, theoretically, an FLNG facility
could, under the appropriate circumstances, prove to be a more cost effective approach to
natural gas production and distribution when compared to currently practiced methods.
However, since the FLNG technology has yet to be proven in practice, an uncertainty as to
whether or not the theoretical benefits outweigh the unknown added costs, associated to the
increased complexity of an unproven technology, exists.
3.2
Unlocking Stranded Gas
Monetization of natural gas from economically stranded reserves is generally accepted as
the most appropriate use for FLNG technology. Economically stranded reserves were defined
earlier in this report as those which could be produced given the current state of technology,
but are deemed uneconomical due to an excessively high cost associated with transporting the
product to an appropriate market. Gas fields in the Asia-Pacific region serve as examples of
such reserves. Even though the production of these fields is feasible from a technical
35
standpoint, the cost associated with developing a means of transportation to a high price
market, such as Japan in the Asia-Pacific case, renders such a project impractical. In order for a
production company to monetize economically stranded gas, the economic environment
surrounding a stranded reserve must change. This change can come by way of lowered
economic barriers, such as reduced costs in bringing the product to market, or added economic
incentives, such as increased prices in the demanding market. FLNG may allow for the former
change, potentially unlocking economically stranded offshore natural gas reserves by
eliminating the need for both the construction of expensive transmission pipeline systems and
the development of separate onshore LNG facilities.
Economically stranded natural gas reserves suffer from a poor geographic disposition in
relation to high price markets. The current modes of fuel transmission to such markets involve
the utilization of either pipelines or LNG tankers. The cost of developing a pipeline has two
major determinants: length and general location. The cost-per-mile associated with
constructing a given pipeline can be estimated depending upon whether that pipeline is to be
built onshore or offshore. Regarding pricing, the average cost-per-mile for the construction of
an onshore pipeline is $4.1 million while that of an offshore pipeline is $7.6 million [23]. Since
economically stranded gas reserves are located a great distance from a high-price market by
definition, the cost of developing a direct transmission pipeline is too high to consider such a
project economical.
Shipment by LNG tanker is a more cost effective method for transporting natural gas over
long distances. Therefore, another approach to natural gas transmission utilizes a pipeline from
the production field to a nearby LNG facility, which can then liquefy the natural gas product for
36
distribution via LNG tanker. If a gas reserve is considered economically stranded, then no such
facility exists in an economically reasonable proximity. Therefore, an LNG facility must be
developed nearby in order to take advantage of the benefits of LNG transportation. As of 2012,
the cost of constructing an LNG plant could reach as high as $1,000 for every MTPA output
capacity of the proposed plant [24]. Along with the cost associated with the construction of a
necessary feedstock pipeline, this approach for monetizing a natural gas reserve can still prove
to be costly, especially for those reserves located far offshore.
Theoretically, FLNG technology can help bring offshore stranded gas reserves to a point of
monetization. Utilization of FLNG eliminates the need to construct natural gas pipelines to bring
the stranded gas to market or to an onshore LNG facility. As stated previously, the average
offshore pipeline costs $7.6 million per mile of construction. Therefore, an alternative approach
to pipeline construction, such as FLNG, becomes increasingly more intriguing the further
removed a natural gas reserve is from shore. FLNG also gains the advantages associated with
LNG transportation, such as an increased access to distant major natural gas markets, without
the development of a separate onshore LNG plant. In summary, there exists a possibility that, at
the right cost, FLNG technology can bring some offshore gas reserves from a stranded position
to a point of monetization.
3.3
Design Challenges
One of the major deterrents to the realization of FLNG technology is the added design
challenge corresponding to placing a traditionally onshore facility offshore. This added
challenge comes in several forms, which can be categorized by size limitation, byproduct
disposal and reuse, operational optimization, and operational and environmental safety.
37
Developing creative solutions to meet the additional challenges of FLNG can help bring the
technology from theory to a safe, efficient practice.
Limitations in the achievable size of an offshore facility are dictated by the capability and
cost of manufacturing and operating the floating facility rather than the availability of space,
since the span of the ocean provides much more area than required by an LNG plant. The
acreage of an onshore LNG plant varies depending upon its capacity potential, but typically
between 50-100 acres are sought out to station such a plant [25]. Developing and operating a
floating facility of this size is impractical; therefore, efficient uses of available plant space must
be determined before the use of FLNG technology can become feasible.
The disposal of process byproducts and the acquirement of reactants become more
complicated issues when an LNG facility is moved offshore. The easiest way in which to dispose
of operational byproducts from a floating facility is to feed them into the surrounding ocean.
However, this practice brings about environmental concerns. In order to protect the oceanic
environment from a substantial human footprint, the disposed byproducts must be held to
strict composition standards before they are released. Achieving such standards may require an
increase in operational costs when compared to those associated to onshore LNG operations, in
which operational waste can be disposed of in hazardous waste storage sites which may not
hold the same requirements.
3.4
Current State of Technology
The true test for FLNG is already underway. Currently, several FLNG initiatives have
entered the planning phase, with some even reaching the point of manufacturing by the time
this report was written. These groundbreaking FLNG projects will help show the true practical
38
effectiveness of the unproven technology and uncover areas of improvement that were not
previously considered.
The movement toward realizing FLNG technology began in 2011, when the Royal Dutch
Shell plc decided to move forward with a multi-billion dollar FLNG project by the name of
Prelude. Since then, several additional initiatives have followed suit, including a Columbian
FLNG project led by Pacific Rubiales Energy and a recently approved Malaysian project led by
Petronas. Alongside the approved projects are similar movements toward FLNG from other
energy producers, including ExxonMobil and ConocoPhillips [26].
Moving forward, if these groundbreaking projects prove successful, they could pave the
way for the expansion of FLNG technology. The future of the world's energy portfolio could
take a shift in the direction of natural gas if FLNG proves to be a solution to unlocking some of
the vast quantities of economically stranded reserves. If both technically and economically
feasible, FLNG technology would result in an increase in the world's economically proved
natural gas reserves. Access to greater amounts of the cleanest burning fossil fuel could
subsequently act as an added motivation for innovation in the uses for natural gas and
potentially reduce the world's carbon emissions by replacing the use of other fossil fuels with
that of natural gas. Thus, FLNG technology can help the world meet the energy challenge of the
future.
39
4. Shell Prelude FLNG Project
4.1
Prelude: An Introduction
Rather than focusing on a hypothetical FLNG facility and keeping the analysis purely
theoretical, this report will analyze FLNG by studying the case of Shell's Prelude FLNG project in
Australia. More specifically, this report will describe how Shell approached the added design
challenges associated with the implementation of FLNG technology and then asses the project's
long-term economic validity through the use of a discounted cash flow analysis. In order to
create worldly context, a brief introduction to the Prelude FLNG project will be provided.
4.1.1
Early Beginnings of Prelude
The catalyst for the Prelude FLNG project dates back to the year 2007, when Shell first
discovered the Prelude natural gas field in its permit area of the Browse Basin, located
approximately 125 miles off the northeastern shore of Broome, Western Australia. A couple of
years later, in 2009, Shell also discovered the Concerto field within the original permit area.
Together, the two fields are estimated to contain approximately 3 trillion cubic feet (tcf) of LPGrich natural gas [27]. This estimated quantity accounts for less than 2.7% of the world's 2010
natural gas consumption, making the Prelude gas field a relatively small discovery compared to
the total market supply.
Unfortunately, the gas contained within the Browse Basin is not connected to the
Australian shore via a developed pipeline and, given the small size of the fields discovered
within the basin, the high cost associated with the construction of a new offshore pipeline
renders typical production and transmission methods uneconomical. Therefore, these
40
circumstances surrounding the Browse Basin gas fields led Shell to consider producing the fields
through the implementation of a flagship FLNG project.
The preparations for the Prelude FLNG project began soon afterward. Demonstrating
the company's effort to bring FLNG technology to practice, Shell has stated that its engineers
spent over 1.6 million hours on the front-end engineering design for the project. In July of
2009, Shell announced that the combination of Technip S.A. and Samsung Heavy Industries
would receive a contract for the design, construction, and installation of its FLNG projects,
based upon its own proprietary FLNG design, over a period of 15 years. Then on May 20, 2011,
Shell made its final investment decision to move forward with the project, allowing the
manufacturing of the facility to begin in October of 2012 at Samsung Heavy Industries' own
shipyard in South Korea. On December 3, 2013, the hull of Shell's Prelude FLNG facility was
floated out of dock [27].
4.1.2
Project Overview
The proposed single-train FLNG design will require 200,000 tonnes of steel to construct
the structure, which will then have to be towed to its final production location and moored in
place over the course of its operational lifespan, which is estimated to be between 20-25 years.
The turret mooring system will consist of suction piles along 24 separate anchor chains, and the
stationed Prelude facility will receive product from subsea wells covering an area of
approximately 83,000 sq. ft. via flexible flowlines, similar to those used by offshore natural gas
production facilities. The facility's production design will be tailored toward the production and
treatment of LPG-rich natural gas, with a capacity of 3.6 MTPA of LNG, 1.3 MTPA of condensate,
and 0.4 MTPA of LPG. At the end of its operational lifetime, the Prelude facility will be docked
41
for inspection and maintenance, with the potential to become operational again afterward.
Figure 10 provides Shell's conceptual design for the FLNG facility [27].
Figure 10: Conceptual design for Shell's Prelude FLNG facility
Generally speaking, the Prelude FLNG project aims to produce the Prelude and Concerto
gas fields, located in the Browse Basin, in order to help supply the growing demand for natural
gas in Asian markets. Japan, South Korea, China, and Taiwan are some of the world's largest
LNG importers and have all experienced increases in LNG imports over the last few years.
Shell's production of the Browse Basin can provide a greater availability of LNG to these
nations, encouraging further increases in their LNG import numbers.
4.2
Meeting the Design Challenge
In order for Shell to move forward with such a project as Prelude, the company must
trust that it has adequately met the design challenges posed by the unpracticed FLNG
42
technology. Shell's confidence in its ability to successfully develop and operate an FLNG facility
comes in part from the knowledge acquired through the increased regularity of large-scale
deep water production practices, since some of the facility's design aspects derive from
offshore production platform designs. This subsection will describe how Shell's FLNG facility
aims to meet space constraints, operational challenges of offshore processing, and safety
concerns.
4.2.1
Addressing Sizing Constraints
The deck of the Prelude FLNG facility will measure approximately 1601 ft. by 243 ft.,
equivalent to an area of just under 9 acres. This size makes Shell's floating facility relatively
compact for its capacity, since a comparable onshore LNG plant would typically require at least
4 times the area, or approximately 25 acres. Shell accomplished this size reduction by moving
the LNG, LPG, and condensate storage tanks (with capacity measurements of 7.77 MMCf, 3.18
MMcf, and 4.45 MMcf, respectively), the water processing facilities, and the power generation
unit below deck. Additionally, Shell further reduced the plant's required deck area by pursuing
a vertical design and stacking the vessels of the treatment and liquefaction units, located atop
Prelude's deck. Lastly, Shell removed the need for large water cooling towers by relying on a
vast resource available to all oceanic facilities: cold ocean water. The combination of Shell's
stacked design and the removal of unnecessary components allowed the Prelude facility to
reach a practical size for a floating structure [27].
4.2.2
Addressing Operational Challenges
Another design challenge of FLNG technology is managing to effectively operate a
liquefaction facility with both limitations in resource accessibility, when compared to an
43
onshore LNG plants, and relative motion of the facility. As mentioned earlier, the Prelude
facility will pull cold ocean water from nearly 500 feet below the ocean's surface to use as a
coolant in the facility's heat exchangers. The heat exchange process will then return the heated
coolant to the ocean, effectively recycling the resource. Shell estimates that Prelude will
process approximately 15.85 million gallons of cold ocean water every hour, and then return
the processed water back to the ocean at temperatures that range between 7.5*C to 16*C
above seasonal ambient temperatures of the location. In order to inhibit microbial growth
within the ocean water pipelines, Shell plans to inject bleach into the ocean water intake
stream. To ensure that Prelude does not pollute the ocean with bleach as a result of this
process, the processed ocean water will undergo a bleach treatment process before being
returned to the ocean. According to Shell, the processed ocean water will be treated to the
point that it contains no more than 0.2 parts per million (ppm) of bleach when it is returned to
the ocean [27]. Therefore, using ocean water as a coolant should reduce Prelude's need to
acquire resources from shore without disrupting normal operations.
The relative motion of the facility caused by oceanic waves poses an operational risk in
the form of sloshing within partially filled containment vessels. Sloshing within containment
vessels can lead to dangerously high impact forces on both the vessel and its supporting
structures. This type of risk is not present within the current LNG industry since LNG tankers are
either full or empty during transmission periods. Therefore, a new solution must be developed
in order to mitigate this risk and allow for the development of FLNG. Shell chose the geometry
of Prelude's containment tanks such that sloshing would be minimized, based upon technical
simulations. Furthermore, Shell has implemented a tank level management procedure to
44
proactively control the effects of sloshing during times of harsh conditions [28]. Addressing
operational issues such as these has allowed Shell to confidently move forward with their
flagship FLNG project, Prelude.
4.2.3
Ensuring Operational Safety
However, finding a purely efficient way to operate an LNG train atop a floating facility in
is not enough in this case, since the location of the Browse Basin is known to be prone to
hurricanes. Any facility wishing to operate within this region must have the structural integrity
to withstand up to category 5 hurricanes. Shell claims that the Prelude facility will be able to
meet such a requirement given its advanced turret mooring system and its additional stability
features [27].
Prelude's turret mooring system features a 305 ft. tall turret which will be moored to
the ocean floor by four sets of anchor chains. Each anchor chain will be secured to the ocean
floor using suction piles, each about 30 ft. in diameter and 140-180 tonnes, which will
penetrate into the earth beneath the ocean's surface. The four sets of chains will each contain
six anchor chains [27]. Together, these anchor chains will keep the turret stationary. In order to
reduce the effects of harsh conditions upon the LNG operation, Prelude's deck will rotate and
weathervane about the fixed turret. With these design features, Prelude is expected to
withstand the hazardous effects of nature without halting production. Figure 11 provides a
graphic of Prelude's subsea components, including the turret's mooring chain system [27].
45
Figure 11: Subsea components of Shell's Prelude facility design
4.3
4.3.1
Economic Analysis
Analysis Overview
In order to analyze the economic validity of the Shell Prelude project, this report will aim
to define the net present value (NPV) of the project's discounted future cash flow as a function
of the sale price of LNG. Once the project's NPV is given as a function of the sales price of LNG,
the project's free-on-board (FOB) breakeven price can be derived. The Platts Japan Korea
Marker (JKM) acts as the benchmark price for LNG sold to Asia, the end market for Prelude's
produced LNG; therefore, the FOB breakeven price will correspond to the Platts JKM required
for the project's NPV to be equal to zero. Above this breakeven price, the Prelude project is
46
expected to create a positive NPV for Shell and, thus, its development should be pursued. This
report will define the NPV of Shell's Prelude project by Equation 1.
N
NPV =
1(1 + i)t
t=O
where
NPV = Net present value of discounted future cash flow
t = year of cash flow relative to reference year
Rt = Net cash flow in year t
i = discount rate
As seen by Equation 1, an analyst must have information regarding the project's
expected revenue and costs over the course of its lifespan as well as an appropriate discount
rate in order to complete the NPV analysis. The following subsections will walk through the
methodology employed by this report to best determine each of these inputs.
4.3.2 Project Lifespan
This report employed the use of Shell-sponsored project specifications when
determining Prelude's operational timeline. Shell has previously announced that the Prelude
facility will remain stationed for production in the Browse Basin for 20-25 years from the time
at which it becomes operational, which is expected to occur in the year 2017 [27]. Therefore, it
is safe to estimate that Prelude will only earn revenue from its LNG, LPG, and condensate sales
from the year 2017 to sometime between 2037 and 2042. For the purpose of this analysis, an
47
operational lifespan of 20 years will be utilized. If the project's production costs never exceed
its revenue earned from sales, this parameter choice will provide a worst-case scenario of the
FOB breakeven price for the project.
4.3.3
Project Revenue
The two main components of a project's earnings are revenue and operational costs. As
previously stated, the project's NPV will be found as a function of the price of LNG to allow for a
calculation of the FOB breakeven price of the project. However, the Prelude facility will produce
not only LNG, but also LPG and condensate, each of which is sold at a price different from that
of the Platts JKM. Therefore, in order to find the Prelude project's NPV as a function of only a
variable LNG price, the sales price of each of these products (LPG and condensate) must also be
written as a function of the variable price of LNG. For the purpose of this particular analysis, the
price ratios of both LPG and condensate to the Platts JKM, in terms of price per volume, will be
held constant through the project's operational lifespan at the current ratios. The price ratios of
these products will be based upon volume, rather than stored energy, since the production
rates of each product component will be estimated in terms of both mass and volume for use in
the cash flow analysis. At the time this report was written, the price of natural gas condensate
could be roughly approximated by that of Brent crude oil (107.64 USD/bbl), LPG sold for 68
USD/bbl, and the Platts JKM stood at 15.56 USD/MMBTU (or approximately 49.08 USD/bbl).
Therefore, throughout the analysis, the sale price of natural gas condensate will be modeled as
220% that of LNG and the sale price of LPG will be modeled as 138% that of LNG, per volume.
48
With the model's price scheme finalized, the last step toward determining Prelude's
revenue over its operational lifespan is to estimate the facility's production numbers for LNG,
LPG, and condensate over time. Typically, gas decline curve theory will be utilized for the
purpose of estimating production rates from a gas field over time. Along with the knowledge of
a reservoir's production properties, a gas decline analysis can provide a reasonable estimate of
expected future production.
Traditional decline curve analysis suggests that production rates from a given well can
be modeled as one of, or a combination of, three standard decline curves known as the Arps
equations. These equations were named after the man who suggested, over 70 years ago, their
effectiveness in modelling wellhead production decline and include a harmonic decline curve, a
hyperbolic decline curve, and an exponential decline curve [29]. Figure 12 provides a
generalized graph of each of these decline curves for the purpose of highlighting their general
differences [30]. The curves shown in Figure 12 have been assigned values to certain variables
for the purpose of providing a more informative visual. These curves do not necessarily
represent actual derived production decline models used in practice.
49
0.
dR
0 1 10
0.1
I,
I
am00
100
Dissolved
Gas-Drive
Reservoir
Gas
Shale
1000
-nuMn*dtftI-1)
-A
HWWrbo
Do** .(b.13
.......
...
......
V.
Figure 12: General graph of Arps Decline Curves
As seen in Figure 12, the three decline curves model production rates similarly through
the early production periods. However, as production moves forward, the decline curves begin
to differentiate themselves. For example, a gas well with a production profile which follows the
model of an exponential decline curve will reach its production limits prior to one which follows
the model of a harmonic decline curve. The use of empirical field data in a decline curve
analysis is preferred in order to determine the best suited decline curve and curve parameters
so as to ensure an accurate model. However, production data from the Prelude and Concerto
gas fields is not currently available since these fields have yet to produce natural gas in practice,
due to each of the fields being deemed economically stranded prior to the initiation of Shell's
Prelude FLNG project.
50
Therefore, this analysis will develop some assumptions regarding the Prelude facility's
production of LNG, LPG, and condensate. Rather than deriving a separate gas decline curve
from unknown reservoir properties and potentially creating an inaccurate production curve,
this analysis will make use of production estimates already offered to the public from Shell.
Shell has previously stated that the Prelude FLNG facility will produce at least 3.6 MT of LNG per
anum, 1.3 MT of condensate per anum, and 0.4 MT of LPG per anum [27]. For the purpose of
this analysis, these production estimates will be held constant throughout the FLNG facility's
operational lifetime and used alongside the pricing scheme, detailed earlier in this subsection,
to determine Shell's sales revenue as a function of the spot price of LNG in Asia. The analysis
will also aim to describe the room for error in production by carrying out a couple of scenarios
in which the actual production numbers differ from these initial production estimates by some
percentage.
4.3.4 Project Costs
Prelude's total project cost will be broken down into its fixed costs, those that accrue
regardless of the facility's production numbers, and its operational costs, those which are
directly proportional to the facility's production and processing operations. The fixed costs of
the Prelude project include the cost associated with acquiring and maintaining the necessary
retention, production, and infrastructure leases from the Western Australian government.
Shell's outward cash flow associated with the cost of developing the FLNG asset will be
accounted for through separate methods detailed in Section 4.3.6 Depreciation Scheduling and
Section 4.3.7 Amortization.
51
Western Australia maintains three separate types of leases relating to the production of
offshore hydrocarbons that will affect the Prelude project's total cost. These include a retention
lease, production lease, and infrastructure lease, all of which impose an initial application fee as
well as annual renewal fees upon the holder of the lease. The application and annual fees
related to acquiring and renewing each of the leases can be found in a Schedule of Fees
document located on the website of Western Australia's Department of Mines and Petroleum.
The relevant fees, as stated in the Schedule of Fees document, are provided in Table 1 [31].
Since the Browse Basin permit owned by Shell, WA-371-P, covers an area of approximately
1,000 sq. km, it will be assumed that Shell is paying the annual production and retention fees
for only 2 blocks [27]. The fee associated with obtaining an exploration lease from the Western
Australian government will be ignored by this NPV analysis since it is a sunk cost at the point of
Shell's final investment decision in the FLNG project.
Table 1: Fixed cost fees relevant to Prelude FLNG project
Description
Fee ($)
Frequency
Production License Application
5,734
Single Occurrence
Retention Lease Application
5,734
Single Occurrence
Infrastructure License Application
5,734
Single Occurrence
Production License Fee
16,352 per block
Annual
52
Retention License Fee
14,672 per block
Annual
Infrastructure License Fee
15,080
Annual
With the project's fixed costs fully defined, the next step is to develop a strategy for
defining the project's operational costs. The total operational cost associated to the Prelude
FLNG project, which will both produce and liquefy natural gas, will be estimated by summing
the individual operational costs corresponding to a the facility's gas development and
production, the facility's liquefaction processes, the shipping of the processed LNG to market,
and the regasification of LNG exports upon arrival to the market. Chemsystems provides an
estimate for each of these operational costs in the case of a South-East Asia onshore facility
exporting LNG to Japan [32]. Figure 13 offers the estimates provided.
Midde Eastito-Japan
South-East Asia to: pan
G Develpmntand Ptoduction
050
1.00
Gas Liuefactin
2:25
225
LNG Shipping
ID5
0.70
LNG Re-gasification
0.0g080
Tito
1 .08
4.75
Figure 13: Operational cost estimates for onshore LNG plants, provided by Chemsystems in $/MMBTU
In the case of a floating plant such as Prelude, the effective LNG shipping cost is likely to
be less than that of a similar onshore plant; however, this analysis will assume that a higher
53
cost is associated with the gas liquefaction process of a floating facility and will compensate the
lower shipping cost. Therefore, the $4.75/MMBTU figure provided by Chemsystems will be
used as the operating cost in this report's Prelude's NPV calculation.
4.3.5
DiscountRate
This report's NPV analysis will discount the future cash flows at the project's Weighted
Average Cost of Capital (WACC). WACC is the weighted average of the costs of a firm's choice of
financing sources, with each cost weighted according to its source's proportion of total
financing [33]. There are two distinct financing sources used in this report's WACC calculation:
equity and debt. The cost of equity refers to the potential returns that would result from
putting that equity toward a zero-risk investment and is dependent upon the interest rate and
the risk of investment. The cost of debt refers to the returns that will be paid to the debt's
creditor and is dependent upon the company's bond yield and the global risk premium.
Equation 2 describes WACC as a function of its inputs, and Equation 3 and Equation 4 detail
how the cost of equity and cost of debt are calculated, respectively.
WACC = C, x
Equity Financing
Debt Financing
Financing +t C+ x
Financingx (1 - Corporate Tax Rate)
Total Financing
T-otal Financing
where
C, = Cost of Equity
Cd = Cost of Debt
Ce = Interest Rate + Equity Risk Premium x I?
where
54
f
= Company's Beta Coefficient
Cd = Company Bond Yield + Global Risk Premium
As of March 31, 2014, Shell's debt to equity ratio stood around 0.25, or a ratio of 1:4. However,
for a project with a capital cost as large as Prelude, a debt ratio is preferred. Therefore, this report's
WACC will be calculated with 80% debt financing and 20% equity financing. The corporate tax rate in
Australia stands at a flat rate of 30% while the national interest rate has been equal to 2.5% for the past
several months. Each of these rates will be used and held constant throughout the project's operational
lifespan. The global risk premium for Shell operating in the Browse Basin of Australia is estimated to be
negligible and will be held at 0% for the purpose of this WACC calculation. Finally, at the time this report
was written, Reuter's listed the Royal Dutch Shell plc f coefficient and company bond yield at 0.68 and
4.58%, respectively [36]. With the use of these values and an equity risk premium equal to 10%, the
WACC equation gives a WACC value equal to 4.89%. This WACC value will be used as the discount rate in
the future cash flow analysis.
4.3.6
Depreciation Scheduling
Shell is likely to spread the capital expenditures associated to the manufacturing of the Prelude
FLNG facility across the lifetime of the project in order to avoid heavy negative cash flows during the
project's development phase. This subsection will discuss the way in which this specific analysis will
spread the value of the Prelude FLNG asset across the project's lifespan, while Section 4.3.7 Interest
Payments will discuss the cost associated with Shell's outstanding debt arising from the project
financing. Depreciation and interest payments will each act as an adjustment spread over the lifetime of
the Prelude project, effectively decreasing Shell's taxable income during the years of production. These
adjustments will help lower the FOB breakeven price for the Prelude project, thus increasing its chance
for proving to be economically feasible. Equation 5 details how a company's taxable income is
55
calculated, while Equation 6 provides the calculation for a company's required tax payments. From here,
it can be understood why costs associated to the asset, such as depreciation and interest payments on
principal debt, are preferred during years of revenue rather than years of early project development and
no revenue. If Shell can spread the costs deriving from its capital expenditures across the lifespan of the
project rather than the first six years of development, it can effectively shield a greater percentage of its
income from being taxed.
Taxable Income = Revenue - OPEX - Interest - Depreciation
Taxes = Taxable Income x Corporate Tax Rate
This analysis will employ a straight-line depreciation schedule to an asset value of $0 beginning
the first year in which the facility produces LNG. This depreciation schedule implies that the asset will
only lose value through years of operation and not during any of the years of the project's development
phase. Therefore, the value of the asset will enter the first year of operation at the total cost of the
FLNG facility and then depreciate over the years of operation toward $0. The straight-line style of the
schedule means that the asset will depreciate in value at a constant rate over the years of its
depreciation. This type of depreciation makes sense for this particular model since production and,
therefore, the use of the facility will be held constant through its operational lifespan.
Shell has estimated the Prelude FLNG facility to cost between $3-3.5 billion per MTPA LNG
capacity. With an LNG capacity of 3.6 MTPA, the estimated cost of Prelude lies in the range of $10.812.6bn [37]. Therefore, the depreciation schedule used in this analysis will begin with the asset value at
the median of this range, $11.2bn. From there, the asset will depreciate annually by 1 / 2 0 th the original
value (due to the 20 years of operation used in this analysis). This amount by which the asset value
depreciates each year will be used as the depreciation adjustment in the calculation for Shell's taxable
56
income. Figure 14 provides a chart detailing the actual depreciation schedule used for this report's NPV
analysis.
Depreciation Schedule
$12,000,000,000
$10,000,000,000
C
$8,000,000,000
0L
$6,000,000,000
-4-Depreciation
-+-Asset Value
$4,000,000,000
$2,000,000,000
16, A.
.L
A.
$0
0
5
10
15
20
Project Year
25
30
Figure 14: Depreciation schedule used in NPV analysis
4.3.7
Amortization
The depreciation schedule accounts for the capital expenditures associated with the
development of the FLNG facility; however, some of the development is financed through debt,
which brings about another cost in the form of interest payments. Therefore, an amortization
schedule must be determined in order to determine the interest adjustments over time. This
subsection will detail how that amortization schedule is modeled in this particular analysis.
57
As was stated in Section 4.3.5 Discount Rate, 80% will be used as the debt ratio for
Prelude's financing. Therefore, Shell will need to acquire 80% of the FLNG facility's $11.2bn
cost, or $8.96bn, to finance this project. The amortization schedule will assume that Shell will
acquire 1/6
of this debt, or approximately $1.87bn, over each of the project's development
years in the form of separate mortgage bonds. Furthermore, Shell will amortize each of these
debts at a constant rate over 21 years so that Shell's debt is completely paid off during the final
year of Prelude's lifetime. The annual mortgage payment, or amortization, for each of these
debts is calculated to be approximately $0.11bn.
Shell's amortization can be broken down into interest payments and principal payments.
Each year's interest payment on the debt is equal to the cost of debt (defined in Section 4.3.5
Discount Rate) multiplied by the outstanding debt, while each year's principal payment is that
which is made to repay the principal of the debt. As principal payments are made, the
outstanding debt reduces. Therefore, as the debt moves toward maturity, Shell's interest
payments will decrease while its principal payments will increase. With the global risk premium
taken to be negligible, the cost of debt associated with the Prelude FLNG project is equal to
Shell's company bond yield, or 4.51%. Figure 15 provides a chart detailing the amortization
schedule used in this NPV calculation.
58
Amortization Schedule
$700,000,000
$600,000,000
AAA*
$500,000,000
A
AA
$400,000,000
* Amortization
AAA
* Interest Payment
$300,000,000
A Principal Payment
A
$200,000,000
*A
MM
$100,000,000
HAmo
$0
0
5
10
15
20
25
30
Figure 15: Amortization schedule used in the NPV analysis
4.3.8 FOB Breakeven Price Cakulation
With the methodology for determining the Prelude project's production schedule,
pricing scheme, operational costs, depreciation schedule, and amortization schedule explained,
an FOB breakeven price can be calculated. The first step is to determine Shell's earnings before
interest, tax, and depreciation (EBITD) for each year as a function of the Asian market price for
LNG. This is done for each year by summing Prelude's revenue and OPEX in the given year. Both
revenue and OPEX are written as a function of a variable price.
Before calculating the corporate taxes Shell is required to pay as a result of its sales
income, the depreciation and interest payment adjustments to the taxable income must be
59
accounted for. Shell's taxable income is calculated by subtracting a given year's depreciation
and interest payment (as defined by the depreciation schedule and amortization schedule,
respectively) from its EBITD. Both adjustments for a given year are not a function of a variable
price, and are fully defined by either the depreciation or amortization schedule. Once a year's
taxable income is found, the tax value paid to the Australian government by Shell is calculated
by multiplying the taxable income by Australia's corporate tax rate (30%).
Finally, the cash flow for a given year can be found. This is done by subtracting Shell's
tax payments to the Australian government from its taxable income. Depreciation of the FLNG
asset is included in each year's net cash flow since the cost of manufacturing the asset was not
considered an expense during the project's development years. Inputting each year's net cash
flow and the project's calculated WACC into Equation 1 gives Shell's Prelude FLNG project NPV
as a function of the sales price of LNG. The FOB breakeven price is then calculated by setting
this NPV function to zero and solving for the variable price of LNG.
This report conducted the same NPV analysis described above for the case of several
different production scenarios in order to determine the reliance of the Prelude project's
economic feasibility upon Shell's production estimates (which predicted 3.6 MTPA LNG, 1.3
MTPA LPG, and 0.4 MTPA condensate). The production scenarios considered in this analysis
include: 15% overstated estimates, 10% overstated estimates, accurately stated estimates, 10%
understated estimates, 15% understated estimates, and production without condensate of LPG.
Table 2 provides the FOB breakeven price result for each of the production scenarios
mentioned above.
60
Table 2: FOB breakeven price results
4.3.9
Production Scenario
(LNG, LPG, COND)
FOB Breakeven Price
($/MMBTU)
Accurate Estimates (3.6, 1.3, 0.4)
8.16
10% Overstated Values (3.24, 1.17,0.36)
8.59
15% Overstated Values (3.06, 1.11, 0.34)
8.84
10% Overstated Values (3.96, 1.43, 0.44)
7.81
15% Overstated Values (4.14, 1.50, 0.46)
7.66
No Condensate/LPG (3.6, 0, 0)
12.42
AddressingModel Limitations
There are several limitations to the financial model developed for the purpose of this report's
NPV analysis. Most of these limitations stem from the fact that many parameters that would likely vary
overtime, such as Prelude's production rates or the price ratios of LNG, LPG, and condensate, were
instead held constant. Additionally, unknowns related to the true value of the FLNG facility and its
financing sources create issues when trying to develop an accurate model. However, to accurately
address these limitations, this analysis would require a greater knowledge of FLNG facilities and
proprietary information from Shell. Since FLNG technology is still yet to be practiced, its effectiveness at
meeting expectations is yet to be seen and the limitations within this model are viewed as unavoidable.
61
5. Conclusion
5.1
Discussion of FOB Breakeven Price Results
The results of this report's NPV analysis are not found to be too shocking. A month prior
to Shell's FID for the Prelude FLNG project, Platts reported the breakeven cost for LNG
delivered to Japan from Australian LNG projects to be in the range of $7-11 per MMBTU [381.
The $8.16 per MMBTU result which corresponds to Shell's estimated production rates finds
itself in the lower half of this range, which seems reasonable especially given the fact that Platts
JKM currently sits at $15.60 per MMBTU and has not fell below $8 per MMBTU since 2008. As
seen in Table 2, a 15% overestimation of production rates would require a near $0.70 per
MMBTU, or 8.33%, increase in the FOB breakeven price. On the other hand, a 15%
underestimation of production rates would result in a $0.50 per MMBTU, or 6.13%, decrease in
the breakeven price. The 15% error band corresponding to production rates is not wide enough
to raise concerns over the economic risk of the project given that a 15% error in the estimation
of production rates is fairly substantial.
However, the case in which the Prelude FLNG facility produces no LPG or condensate is
rather concerning. In this scenario, the breakeven price was calculated to be $12.42 per
MMBTU, well above that corresponding to any of the other scenarios. If Prelude and Concerto
were known to produce solely natural gas, the Prelude FLNG project would likely be deemed
economically inefficient. Although the Platts JKM stands above this particular breakeven price
62
today, the Rice World Gas Trade Model predicts that the JKM will spend most of Prelude's years
of operation below a value of $12.00 per MMTBTU. Figure 16 provides the JKM predictions
made by the Rice World Gas Trade Model [39]. According to the JKM values predicted by this
model, as long as the Prelude facility produces within a 15% error band of Shell's production
estimates, the project should prove to be economically beneficial to Shell.
2010$/mef
$1&oo.
$ c
- - - - -- - - --
- - --
$6.00
$
-4 -----------------------------$2.00~
-------------------------------
Figure 16: Predictions of JKM and Henry Hub prices by Rice World Gas Trade Model
5.2
Advancing FLNG Technology
Shell's Prelude FLNG facility will set the standard for the future of FLNG technology. If
the Prelude project proves to be economically successful, it is certain that the second wave of
FLNG initiatives will aim to model at least some of its design after Prelude's most robust and
proven features. However, if the Prelude project becomes an economic burden to Shell, future
63
FLNG endeavors will aim to avoid some of the facility's uncovered design flaws. Therefore, the
first wave of FLNG projects, headed by Shell's Prelude initiative, will clarify the necessary path
to the advancement of FLNG technology and the unlocking of much of the world's offshore,
economically stranded reserves. Through case studies of the FLNG projects in practice, the
industry can move in the direction of a more efficient and less costly FLNG technology, which
would increase the technology's feasibility in areas of the world where its use is currently
considered uneconomical. Additionally, a stronger understanding of the lifetime costs and
benefits associated with FLNG will allow for more reliable NPV analyses than the one
performed in this report, thus reducing some of the risk associated with undertaking an FLNG
initiative. Together, an expanded knowledge of FLNG in practice should, in turn, allow for the
expansion of its use in practice.
Another known challenge to the advancement of FLNG technology is determining an
economically feasible design for lean FLNG. Lean FLNG corresponds to an FLNG facility that
produces LNG from a lean natural gas reservoir, or a gas reservoir that is not rich in LPG or
condensate. As was seen in the results of this report's FOB breakeven price calculations in Table
2, producing from a reservoir lacking LPG and condensate benefits would have a great impact
on the FOB breakeven price for the Prelude project. With an expected capital cost of $11.2bn,
the Prelude project would likely not reach the point of FID if it were not for the added economic
benefits of LPG and condensate production. Therefore, in order to economically produce from
lean natural gas reservoirs, a more streamlined design must be agreed upon. Such a design
might aim to further reduce the required area for the processing and storage units in order to
reduce the design's total capital cost in order to reduce the project's breakeven price. However,
64
the expansion of rich FLNG production may effectively reduce LNG prices and further reduce
the highest possible breakeven price for lean FLNG production, increasing the difficulty in
finalizing an economically efficient design. Therefore, it is likely that production companies will
not rush into the relatively more risky, when compared to rich FLNG production, practice of
lean FLNG.
5.3
Prelude's Potential Impact
In addition to Prelude's impact on the advancement of FLNG technology, the project will
also have an effect on the Asian market as well as Australia. At a 3.6 MTPA LNG capacity,
Prelude can offer the Asian LNG market 117% of Hong Kong's annual natural gas demand each
year [27]. This additional energy supply can help Asia meet an energy demand that is expected
to continue its growth due to increases in population and living standards. The Institute of
Energy Economics, Japan (IEEJ) estimates that Asia's population in 2035 will be nearly 28%
greater than that of 2007 and that Asia's energy demand in 2035 will be nearly double its 2007
figures [40]. Meeting a majority of Asia's increased energy demand with natural gas rather than
other forms of fossil fuels will help reduce Asia's potential carbon emissions. Currently, China,
Japan, and South Korea stand among some of the countries with the highest carbon outputs
per capita. Unlocking stranded gas reserves will increase the availability of natural gas to the
Asian market and likely ease the fuels opportunity to increase its share of the Asian energy
portfolio. Finally, with an increase in the LNG supply to the Asian market, the relatively high
Platts JKM can be expected to decrease. Currently Platts JKM stands at $15.60 per MMBTU
while the Henry Hub spot price is equal to $4.54 per MMBTU. A decrease in the relatively high
Platts JKM would allow for cheaper energy prices in the Asian market.
65
Australia benefits from Shell's Prelude project by way of tax revenue as well as an
increased employment rate. Through the NPV analysis, it is estimated that Shell will pay a total
of just over $1.62bn in corporate income tax to the government of Australia over the course of
Prelude's operational lifetime. More indirectly, Shell's Prelude project will likely open the door
for an expanded use of FLNG for the production of Australia's previously deemed economically
stranded gas fields, further increasing Australia's future tax revenue. In addition to the direct
tax payments to Australia, Shell has made an effort to hire local Australian's to support its FLNG
facility as a way of giving back to the native country. After announcing the FID of Shell Prelude
FLNG, Shell ramped up its Australian workforce in anticipation of the facility becoming
operational. Shell aims to double its Perth office numbers from 500 to 1000 employees by the
year 2015 [27]. In summary, if Shell's Prelude FLNG project proves successful, it could mean
large economic incentives for Shell and Australia, a significant impact on the Asian energy
market, and the beginning of an era of FLNG projects. A successful Prelude project could, in the
end, help the world as it edges closer and closer to the future energy challenge.
66
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