LNG LIQUEFACTION —
NOT ALL PLANTS ARE CREATED EQUAL
Authors:
Heinz Kotzot - Section Leader, LNG and Gas Processing
Charles Durr - Energy Technology
David Coyle - Technology Manager
Chris Caswell - Principal Technical Professional
Publication / Presented:
Date:
Paper PS4-1
ABSTRACT
As the LNG industry has matured, there is often an inclination to compare the
successes and challenges among projects over time. Many publications have fallen into
the habit of using a specific cost term of “dollars (USD) per ton of annual LNG
production” as an indicator for comparing the engineering and execution skills of owners,
licensors and contractors. This dollar per annual ton benchmark, commonly abbreviated
as “dollars per ton” is highly dependent on site specific factors. These factors include the
remote nature of the site, local content requirements, design criteria, marine conditions,
design practices, and scope differences. The purpose of this paper is to discuss the
impact of such factors and determine the relative effect each factor could have on the
benchmark cost for a specific project.
The analysis begins with a minimal scope plant, in an environment where all
conditions are ideal, to establish a lowest cost LNG project. Individual site and scope
specific factors are then added to determine the impacts on the plant benchmark cost. As
a result, the unavoidable local issues are thus quantified. Furthermore, site specific
criteria, often imbedded in a project design basis, are more clearly defined by
enumerating and quantifying the elements that differ from a low cost reference design
with a minimal scope. In addition to the technical analysis, a review of commercial
issues is presented for the benefit of a technical audience. Commercial risks are entered
into a capital asset pricing model to determine an additional project specific element of
each cost benchmark.
PS4-1.1
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INTRODUCTION
Building any multi-billion dollar project requires a well coordinated plan, aligned
project sponsors, and financial backing. The viability of such a project will be scrutinized
on a continual basis, sometimes even after the project is completed.
In order to develop a liquefaction facility for the 21st century, a few key elements are
necessary to place a new project on the LNG world map:
•
•
•
•
•
•
Having the right location
Having the right partners
Having the right financial plan
Determining the right equipment
Delivering the right equipment to the site at the right time
Having the right people to put it all together
The difficult part of this plan is to define what is “right” in order to achieve the lowest
cost and the shortest schedule. “Lowest cost” is the most crucial driving factor in every
project. Although Life Cycle Cost is often cited as a criterion in plant design, it seldom
becomes more influential than lowest capital cost. This paper will determine the major
contributors to the cost of an LNG plant and why certain elements are necessary, which
add a corresponding, and unavoidable, cost.
The specific cost of an LNG plant has become a fashionable metric to compare
projects against each other. This dollar per ton per year number, commonly referred to as
“dollars per ton”, is frequently cited in technical and commercial literature in spite of the
fact that the location, the market, and the scope make valid project comparisons difficult.
Due to ‘economy of scale’, a relative increase in capacity will usually lower the
specific cost as long as equipment sizes increase in a proportional manner (as opposed to
adding one or more modules of equal capacity). In addition, variations in capital cost are
strongly affected by:
•
•
•
•
Plant location
Cost of labor
Feed gas composition
Product specification
Competition among contractors and liquefaction process technologies are often
attributed as significant factors that affect specific cost. The cost impact of technology
selection is not as significant as often portrayed in the total project cost, but technology
will impact the operation, availability, and efficiency of the plant. With equal conditions
among participating contractors, the cost impact of contractor competition is limited.
Most of the project cost is beyond the influence of the designers and contractors and is
mainly a function of site related conditions, project development, and project execution
objectives. Capital cost reduction must be balanced with other important objectives, such
as safety, reliability, and operation and maintenance practices.
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For this paper, a base production rate of 4.5 Mt/a (million tons per year) of LNG is
chosen to allow fair comparisons without distortion due to ‘economy of scale’. In the
analysis, this paper addresses only the LNG liquefaction portion of the LNG value chain,
as highlighted in Figure 1.
Gas Field
Liquefaction
P lant
LNG Storage Tank
LNG Storage Tank
LNG Tanker
PRODUCING REGION
TRANSPORTATION
Vaporizers
CONSUMING REG ION
Figure 1: The LNG Value Chain and the focus area for specific liquefaction cost
In the commercial evaluation, all elements of the LNG chain have to be considered,
because every element of the chain contributes to the cost of financing. Commercial
considerations, which are presented for a technical audience, are included in this paper to
show the significant impact on the overall cost of an LNG project.
As the global market for LNG has developed, financing has always required careful
planning and is becoming increasingly complex. Aspects to be considered include
project rate of return, long-term demand, political and regulatory stability, production
covered by take-or-pay arrangements, risk allocation among the sponsors, the
creditworthiness of the buyers and the availability of security or guarantees.
This paper will attempt to quantify these technical and commercial influences in order to
develop transparency in regard to LNG specific cost.
TECHNICAL
The primary drivers for the capital cost of an LNG liquefaction facility are site
specific in nature. Surprisingly, less than 50% of the LNG plant cost is capacity related.
As a result, most of the cost of an LNG liquefaction project is beyond the influence of the
design engineer and is a function of site related conditions, project development and
project execution efforts.
Although there is no typical or standard LNG plant, the major elements that are found
in most LNG plants include:
• a feed gas handling and treating section
• a liquefaction section
• a refrigerant section
• a fractionation section
• an LNG storage section
• a marine and LNG loading section
• a utility and offsite section
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Even with all these elements, each LNG plant is unique to a specific location and
market destination. A typical cost distribution for an LNG plant is shown in Table 1.
Table 1. Cost Distribution for a “Typical” Liquefaction Facility
Liquefaction Cost Distribution
Percentage of
Total Cost
Gas Treating
Fractionation
Liquefaction
Refrigeration
Utilities
Offsites (storage, loading, flare)
Site preparation
Total
7
3
28
14
20
27
1
100
While this information may be of interest, the table does not provide insight as to
what the plant cost will be for a specific location with a certain feed composition, array of
products, design specifications, and site conditions. This paper will discuss relative cost
of the various plant sections, instead of using percentages. By starting with the most
basic plant design, site specific elements will be added to the project to show the impacts
on plant specific cost.
Alternative Cost Distribution
Instead of evaluating the total plant cost by process area, this paper will present the
plant cost in five major categories: material related cost, location related cost, sponsor &
contractor cost, labor cost, and financing cost. Defining overall plant cost within these
areas will allow for cost sensitivity analysis of project specific items, and how strongly
they influence the cost metric.
Material Related Cost. This cost component includes all tagged equipment and
auxiliary material, including bulks (e.g. piping, electrical, structural steel, concrete, etc.).
Material costs can vary substantially from historical norms depending on the technical
requirements of the project and the condition of the materials market during the
procurement effort.
Location Related Cost. Site preparation is not a large component of the plant cost,
but the cost of site preparation will vary significantly with the soil conditions and
location. This cost is also dependent on the plant size. A separate sensitivity analysis will
show the cost effects for different degrees of site preparation work. LNG storage tanks
are not a strong function of plant production rate, but depend on ship size and loading
frequency. Similarly, the cost of marine facilities is largely independent of plant capacity
and configuration and totally depends on the location of the plant.
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Sponsor and Contractor Cost. This element of total project cost covers the owner’s
personnel used during project development and items such as legal, permitting, etc. The
cost for the owner’s personnel is commonly estimated as 10% of total plant cost. The
contractor cost includes engineering, construction management, and other related costs.
Labor Cost. This cost element consists of the labor cost at the plant location, which
is commonly identified as a “subcontract” cost. Although this cost includes some
material related items such as paint and insulation, the vast majority of this component
covers the workhour cost for erecting the plant.
Financing Cost. The financing cost includes the interest on equity and debt, as well
as the operating capital necessary for the initial phases of the project until LNG revenues
will cover operating costs. This cost is seldom included in the evaluation of the specific
cost metric. Upon review, these financing costs rank on the same level as labor,
sponsor/contractor, and equipment costs.
Capital Cost (CAPEX) versus Life Cycle Cost
All project stakeholders would prefer a low CAPEX and a low Life Cycle Cost
project. This commercial outcome is the most desirable goal for any project. However, as
the CAPEX is the largest single component of the life-cycle cost and to avoid the
complications of life-cycle analysis, this paper will only address the CAPEX of a project.
KBR has developed a cost analysis model that allows detailed modifications to a
project, such as adding equipment, modifying labor cost and efficiency, or adjusting the
cost of capital based on risk assessment. Results from this model will be presented for a
variety of plant configurations giving an absolute cost for the referenced areas of expense.
The plant costs are reported using a generic metric of currency per annual ton of LNG
product, symbolized by “¢/t” and referred to as “currency per ton”. This metric allows
easy comparison from one design with known parameters to another with assumed (or
known) differences.
Plant Configurations
The primary factors that set the plant configuration are:
•
Feed gas composition and conditions that establish the gas treating and NGL
recovery
•
LNG Product Specifications, which control the severity of NGL recovery and
nitrogen rejection
The pictograph in Figure 2 illustrates the elements of feed gas treating that could be
required for any LNG project and the corresponding shrinkage of the available feed gas to
achieve the targeted LNG capacity. Higher levels of NGL recovery may be driven by the
overall product economics; i.e. if the value of LPG exceeds the value of incremental
LNG. Although deep NGL recovery can improve the revenue stream and life-cycle cost
for the entire project, it will increase the metric when evaluating LNG specific cost.
PS4-1.5
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100%
Plant
Feed
`7 0 - 8 0 %
Maximum Treating Plant
Liquid Slug Condensate
Removal Stabilization
Acid Gas
Removal
Water
Removal
Fuel Gas
NGL
Nitrogen
Removal
LNG
Boil Off
Figure 2. Maximum Feed Gas Treating and the Effect on LNG Production
In order to develop proper cost comparisons for different project configurations, the
analysis will keep the following items constant:
•
Production rate of 4.5 Mt/a of LNG
•
95% plant availability
•
Average ambient temperature of 22ºC.
•
Gas turbine drivers and air cooling
Development of the Base Plant
If the feed gas arriving at an LNG plant is within the range of the required product
specifications, only a core plant is needed, which includes liquefaction and refrigeration.
The base plant cost (defined as Plant 1) is determined by the minimum number of
equipment items that would be required for such an LNG project. This scenario could be
achieved by the presence of an existing upstream LPG recovery plant. Figure 3 illustrates
this base scenario.
100%
Plant
Feed
95%
Minimum Treating Plant
Fuel Gas
LNG
Boil Off
Figure 3. Plant 1 – Minimum Feed Gas Treating
The base plant will require a minimal scope for utilities and offsite facilities. This
scope would include LNG storage tanks, a jetty with loading equipment, relief systems,
fire protection, and the storage of imported refrigerant. This scheme could be developed
if an LNG plant is adjacent to an industrial complex. Utilities such as electric power,
water, effluent treatment, and heating and cooling medium can be obtained from outside
the LNG plant boundary limits. This example is represented by Figure 4.
PS4-1.6
Inlet
Flare & Liquid
Burner
Liquefaction
Propane
Refrigeration
Product
Storage
Refrigerant
Storage
MR Refrigeration
Loading
Utilities
Offsites
Process Train
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Shipping
Fire
Protection
Figure 4. Plant 1 – Minimum Number of Units in LNG Facility
Plant 1 will be incrementally expanded by adding utilities, acid gas treating,
fractionation, extensive feed gas treating, and other processes that could be required at
various locations. Plant 1 results in a small LNG plant, where utilities that are imported
result in an increase in operating costs for a minimum capital cost. This scenario can be
achieved by upstream feed gas treating (reflected in feed gas price) with imported utilities
adding to operating expenses instead of capital investment. The plant will be increased in
size, adding treating and processing units, up to the maximum (Plant 6), as shown in
Figure 5.
AG Disposal
Utilities
Offsites
Process Train
Slugcatcher
Inlet
Fractionation
Flare & Liq.
Burner
Inhibitor
Recovery
Liquefaction
Product
Storage
Power
Generation
Fuel Gas
Sea Water
Fresh Water
Stabilization
Propane
Refrig.
Dehydration
& Mercury
Removal
AGRU
MR Refrig.
Refrigerant
Storage
SRU & AG
Enrichment
Loading
Heat
Medium
Diesel
Storage
Air &
Nitrogen
BFW/Steam/
Condensate
Waste Water
Effluents
Fire
Protection
Figure 5. Plant 6 – Maximum Number of Units in LNG Facility
PS4-1.7
Shipping
Paper PS4-1
Outlining the Six Design Cases
Plant 1, illustrated in Figure 4, includes only the process units that are required for
liquefaction. Feed gas arriving at the plant boundary limit is expected to be ready for
liquefaction. In this case, all utilities are imported except fire protection and relief system
equipment which is integral to the safe operation of the facility. Offsite facilities include
only LNG storage and the loading system.
Plant 2 includes all items in Plant 1 plus all utility systems while Plant 3 will include
all of the items in Plant 2 with the addition of feed gas treatment units. The treatment
systems included in Plant 3 are acid gas removal (AGRU), dehydration, and mercury
removal.
Plant 4 will add a fractionation unit to Plant 3. The presence of a fractionation unit
includes additional equipment for LPG storage and loading.
Plant 5 will add extensive feed gas treating facilities to Plant 4. These facilities
include a slug catcher, condensate stabilization, and the provision for high CO2
extraction within the AGRU. As a result of the high CO2 extraction, there will be
accommodation for CO2 sequestering.
Plant 6 will add a sulfur recovery unit (SRU) to Plant 5 and provide for maximum
LPG recovery within the process unit. An overview of the units for Plant 6 is illustrated
in Figure 5.
The comparison of the six cases will highlight the effects of site specific criteria on
the overall project cost. Each case has a different cost per annual ton due to the particular
scope required to produce the same amount of LNG. The baseline result for each case is
presented in Table 2. The metric is shown as an internally developed “currency per
annual ton”, abbreviated as ¢/t. This currency unit can be used to allow comparison
among designs with known parameters to other locations with assumed (or known)
differences.
Table 2. Variation of Specific Plant Cost Based on Site-specific Criteria
Plant 1
Plant 2
Plant 3
Plant 4
Plant 5
Plant 6
Mt/a
#
4.5
99
4.5
137
4.5
202
4.5
255
4.5
327
4.5
397
Cost of Material
¢/t
38
50
61
69
86
110
Site Preparation
Tanks
Marine Facilities
¢/t
¢/t
¢/t
2
17
26
3
17
26
4
17
26
5
22
26
7
22
26
8
22
26
Sponsor & Contractor Cost
Labor Cost
Financing Cost
¢/t
¢/t
¢/t
41
39
37
53
53
45
74
77
56
91
97
67
114
124
80
138
150
95
Total Cost at Startup
¢/t
200
247
315
377
459
549
Production Rate
Equipment Count
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Changes to an individual cost item, such as site preparation, will affect other cost
elements of the table. Therefore, an increase of the site preparation cost will have a
greater effect on the total cost than the basic change of cost in that row. The sensitivity
analysis in the following paragraphs will show the overall effect on the total cost as a
function of basic changes in scope.
Examining the Elements of Specific Plant Cost
Cost of Material. As the number of equipment items increases, the total cost of
material will increase. However, the relative increase in equipment cost over the six
configurations rises at a lower proportional rate than expected, since major equipment,
such as refrigerant compressors, process drivers, and the main cryogenic heat exchanger
(MCHE), are already included in the base configuration. The cost of material includes
bulk materials and any other costs that are related to equipment (e.g. electrical items).
The cost of materials is a primary concern in the currently active marketplace to build
baseload LNG facilities. The proportion of material cost to total plant cost will affect
comparisons of specific cost among LNG projects as the material market has outpaced
economy of scale benefits over recent years.
Site Preparation. The required plot area will increase as a function of the total
equipment count. Therefore, the cost for site preparation increases, from Plant 1 through
Plant 6, with the incremental scope added to each plant. In Table 2, basic site preparation
cost is included in the calculation, which requires some earth movement-type work for
each example. Table 3 illustrates the relative impact of a less advantageous jobsite which
could significantly increase the site preparation cost and contribute to the increase in
overall cost.
Table 3. Variation of Specific Plant Cost Based on Enhanced Site Preparation
Production Rate
Equipment Count
Base Site Preparation Cost
Total Cost w/ Original Site
Preparation
Revised Total Cost w/
Enhanced Site Preparation
Plant 1
Plant 2
Plant 3
Plant 4
Plant 5
Plant 6
Mt/a
#
4.5
99
4.5
137
4.5
202
4.5
255
4.5
327
4.5
397
¢/t
2
3
4
5
7
8
¢/t
200
247
315
377
459
549
¢/t
210
261
335
404
493
592
Tanks.
Although many plants have used single containment (SC) tanks over the
last 40 years, the trend is now toward the use of full containment (FC) tanks. Full
containment tanks reduce the plot space required for LNG storage, but increase the tank
cost as much as 70% [3]. In addition to increasing the cost, FC tanks require a longer
construction time, which may have a cost impact on the schedule. The LNG storage tank
cost does not vary in our constant capacity analysis, but cost differences could arise due
to varying soil and seismic site conditions. For the analysis in this paper, site deviations
for LNG storage are not included. As seen in Table 2, the LNG tank cost is kept constant
for all cases and LPG storage tanks are added to the cost for Plants 4, 5, and 6.
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Marine Facilities. In general, LNG liquefaction sites are located in remote locations
with less favorable conditions than those in major population centers. To reach a sea bed
clearance of at least 13.5 m, the jetty head needs to be located far enough offshore or
dredging will be required. Some locations may also require a breakwater (i.e. a physical
wave barrier) to achieve the necessary targets for ship loading availability. The costs for
marine facilities can be quite significant and are totally independent of the process
configuration and plant capacity, unless a second berth is required to offload a high plant
capacity. For the 4.5 Mt/a facility, a 700 m long jetty trestle and a breakwater was
considered.
The jetty consists of two major sections, the jetty head and the trestle. The
construction of the jetty head, consisting of breasting dolphins, mooring dolphins, and
gangways, will vary little from site to site. The trestle cost is primarily dependent on its
length and sub-sea soil conditions, which will affect both the structure and the LNG
loading lines. If the jetty head needs to be moved further offshore, the trestle length will
increase as well as the overall cost of the marine systems. In some cases, the trestle
length could extend to several kilometers. To review the sensitivity of a longer jetty
trestle, the impact of a 3 km jetty extension is shown in Table 4.
Table 4. Variation of Specific Plant Cost Based on Enhanced Marine Facilities
Production Rate
Equipment Count
Base Marine Facility Cost
Total Cost w/ Original Marine
Facilities
Revised Total Cost w/
Enhanced Marine Facilities
Plant 1
Plant 2
Plant 3
Plant 4
Plant 5
Plant 6
Mt/a
#
4.5
99
4.5
137
4.5
202
4.5
255
4.5
327
4.5
397
¢/t
26
26
26
26
26
26
¢/t
200
247
315
377
459
549
¢/t
218
265
333
395
477
567
Sponsor and Contractor Cost. For this paper, the cost for the sponsors is kept at a
constant ratio of the total plant cost, but could vary for issues such as permitting and legal
costs. As each plant requires additional scope, the sponsor costs will increase due to the
added complexity. The contractor cost is a function of the scope of work and the project
location, and is determined in proportion to the number of equipment items. The
contractor cost includes home office services, construction management, construction
equipment and temporary facilities. Business expenses that are not part of the other
categories are included in this section.
Labor Cost. A major contributor to the specific cost metric is the cost of labor,
which is both plant size and location dependent, and varies significantly based on project
location. With labor costs accounting for up to 50% of the cost of construction, the
impact of labor has to be considered separately from the cost of equipment. The
difference in labor from site to site can be as much as US$50/ton [4]. The cases
presented in Table 2 are for a labor rate and productivity factor for an African location.
Table 5 illustrates relocating the plant to a more expensive location (e.g. Australia) which
will significantly change the contribution of labor to the metric for specific cost.
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Table 5. Variation of Specific Plant Cost Based on Higher Labor Cost
Plant 1
Plant 2
Plant 3
Plant 4
Plant 5
Plant 6
Production Rate
Equipment Count
Mt/a
#
4.5
99
4.5
137
4.5
202
4.5
255
4.5
327
4.5
397
Base Labor Cost
¢/t
39
53
77
97
124
150
Total Cost w/ Original Labor
¢/t
200
247
315
377
459
549
Revised Total Cost w/ Higher
Labor Cost
¢/t
239
299
391
475
583
701
Financing Cost. The cost of financing, i.e. the interest required for equity and debt
during project development, will vary according to the risk and availability of capital for
a specific project. Due to the complex nature of project financing, this subject is
addressed in the commercial section of this paper.
Additional Cost Contributors
Stick Built Construction vs. Modular Design. Most plants are stick built
(constructed piece by piece) unless the availability of labor, cost of traditional
construction, or adverse climate conditions favors a modular design. Modular design is
proposed when stick built construction is not feasible based on the site conditions and the
project execution plan. Modular design allows the manufacture of sections of the plant at
specialized industrial fabrication yards, and is commonly used in the design of topsides
for offshore projects. This approach is intended to relocate construction labor and reduce
the magnitude of site-specific construction costs. Modular design allows parallel
construction paths, but can add schedule risk if shipping the modules has to occur within
a small window of favorable weather conditions. In general, there is no cost advantage to
modular design. Commonly, more structural steel and engineering is required than for a
stick-built plant, but a modular design could mitigate the escalating costs anticipated for a
challenging or remote location.
Environmental Issues. Project costs influenced by environmental issues mainly
address plant emissions. Guidelines from the World Bank are commonly applied for NOx
emissions, which determine the limits on gas turbine exhaust and required mitigating
controls. In addition to turbine emissions, another major issue is the management of the
acid gases removed from the feed gas for the plant.
Acid gas present in the plant feed can have varying levels of CO2, sulfur, mercaptans,
and H2S. Acid gas removed from a feed with low CO2 could be discharged to the
atmosphere, but if the acid gas contains sulfur or hydrocarbons, incineration is required.
In some cases, a sulfur recovery unit (SRU) is necessary, which requires an acid gas
enrichment unit upstream of the SRU. In environmentally conscientious areas, projects
may require CO2 sequestering, which results in extensive acid gas handling for reinjection into a nearby deep reservoir. For Snøhvit LNG, Statoil estimated an investment
cost of 190 million US$ for CO2 sequestering alone, which includes compression and
drying facilities [5].
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Process Operation. Many papers and presentations have discussed the impact on
CAPEX, operating costs, and operability for the following areas:
•
•
•
•
•
•
Compressor drivers (Steam Turbine, Gas Turbine, Electric Motor)
Heat Rejection (Seawater, Cooling Water, Air)
Heat Medium
Plant Availability Factors
Liquefaction Process Technology
Other plant differentiators
These considerations have been omitted from this paper in order to focus on the basic
issue of the major cost contributors and their effect on the “currency per ton” of
production.
Ambient Air Temperature. If the annual ambient temperature fluctuation is minor,
e.g. areas close to the equator for an air cooled plant with gas turbine drivers; the impact
on the production is relatively minor. In areas with a larger ambient temperature
fluctuation, the plant can be designed for a low, high, or average air temperature. If the
plant is sized for a low ambient condition, the equipment will be underutilized for most of
the year; if sized for a higher ambient temperature, the equipment will be constrained for
most of the year. Finding the right balance is a challenge for the designer, if the plant
capacity is not dictated by marketing.
For the same plant configuration, relocating the plants to a site with a 5 ºC higher
temperature profile will decrease the plant production by approximately 4 %. Due to the
decrease in production rate, the specific plant cost will rise accordingly, as shown in
Table 6. Reducing the plant availability will have a similar effect as raising the design
temperature.
Table 6. Variation of Specific Plant Cost Based on Higher Ambient Temperature
Original Production rate
Original Total Cost at Startup
Reduced Production Rate
Revised Total Cost at Startup
Mt/a
Plant 1
4.5
Plant 2
4.5
Plant 3
4.5
Plant 4
4.5
Plant 5
4.5
Plant 6
4.5
¢/t
200
247
315
377
459
549
Mt/a
4.3
4.3
4.3
4.3
4.3
4.3
¢/t
209
258
329
395
480
575
Safety. There is no clear “cost of safety” for a plant unless the cost of insurance can
be considered as part of the overall cost metric. If proper layout rules are followed and
the inventory of liquid hydrocarbons is kept low, a plant can be considered safe at startup.
In addition, if the proper operating and maintenance rules are implemented and followed,
the plant can be safe throughout its useful life.
Other Cost Items. There are other site specific cost issues that are beyond the scope of
this paper, but affect the overall cost depending on the specific project requirements.
These issues can add to the cost of equipment, engineering workhours, investments in the
host country, or other costs passed through to the bottom line. Some of these issues
include client or regional specifications, taxes and import duties, local content
requirements (e.g. training), and local infrastructure development.
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COMMERCIAL
The following section regarding commercial issues is presented for the benefit of a
technical audience. The concepts are comprehensive enough to support the evaluation of
LNG specific cost. A fully comprehensive understanding of the commercial issues
regarding the LNG value chain is beyond the scope of this paper.
The commercial aspect of an LNG project addresses the financeability that leads to an
“investment grade project”. With the cost of funding varying significantly with the
commercial risk, financing will contribute to a plant’s specific cost. These commercial
risks are based on facts and conditions specific to the locations along the entire LNG
chain and the strengths of the sponsoring parties. Items that are considered by
commercial parties include:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Reservoir size and asset quality
Expandability
Stability of reservoir owner
Predictability of tax regime/regulations in host country
Level of proven technology
Participating company track record
By-product economics
Transportation advantages
Access to open and proven markets
Long term contracts for the entire LNG chain
Customers and markets
Pricing formula
Strength of marketing entity
Pricing stability
Location
This list can grow longer and more complex as the parties involved anticipate and
address every potential risk. However, the most important considerations are:
•
•
The issues that guarantee the return of investment
The impact of the uncertainties
This section addresses the major risks and attempts to quantify the impact on the cost
of financing. The model presented might not necessarily be among the work processes of
the financing companies, but the model illustrates the decision process and is meant to
inject some transparency into the complexity of financing.
Equity and Debt
The equity portion of a project can vary significantly. If the projects sponsors choose
a 100% equity arrangement, they can avoid complex financing issues; however, the
immense cost of an LNG project will impact the balance sheet of even the largest
company, requiring most projects to seek outside financing. Since the interest required for
equity can be between 4 and 5 % above the interest to incur debt, the ratio of equity to
debt will heavily impact the overall cost of financing. For a low risk project, the equity
portion can be as low as 10% and increase to 30% to 50% for a high risk project.
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Assessing commercial risk is what keeps many owners, partnerships, financial
institutions and analysts in extensive negotiations to ensure each member can assure a
win-win situation to their stakeholders. For example, a low risk project might qualify for
a cumulative interest rate as low as 8%, while a high risk project would have to offer 15%
or more to attract the necessary funds.
A project relies on the credit rating of its sponsors to mitigate risk. The sponsors
might even have some obligations beyond their equity obligations, such as a completion
guarantee or limited price support. To achieve investment grade ratings, the sponsors may
put a nominal amount of their assets at risk for a limited time. There are many
publications that discuss the issues to be considered; however, it is difficult to clearly
determine the value or cost of these non-technical considerations.
Assessing the Risk
The element that impacts the cost of money beyond a baseline is risk. This paper will
address only the major risk factors and use a simplified CAPM (Capital Asset Pricing
Model) to quantify risk. For each risk element we assign a risk factor between 1 (low
risk) and 5 (high risk). These individual factors are combined in a factored summation
(ß) which will be entered into the following CAPM formula:
E(Ri) = Rf + ß (Rm - Rf)
or
E(rate of return) = R(risk free interest) + ß ( R(expected return of market) - R(risk
free interest) )
This rate of return is used to determine the cost of financing. Based on a “Risk Free
Interest” of 4 % and an “Expected Return of Market” of 7%, the ß factor will be
determined for two projects with opposite risk profiles. The results of these calculations
are included at the end of this section.
Thomson Financial, which sponsored the pfi – market intelligence publication LNG
Finance: Funding the Fuel of the 21st Century [6], suggests three levels of analysis:
•
•
•
Project level risk
Sovereign risk
Institutional business and legal risk
As there are many references that address these risks in great detail, this paper will
only highlight the major issues.
Project Level Risk. Project level risk addresses the contractual foundation that
protects the investors from market, operating and ownership risk for assurance of
repayment. In essence, the project and local law will give investors the security of the
entire project’s assets. Financial leverage is used to find common ground for multisponsor projects that have different relative strengths that impact the cost of funding;
especially if local partners have sub-par investment ratings and include political risk. The
choice between an incorporated and unincorporated joint venture is driven by the
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partners’ willingness to seek funds on a project basis rather than individually. This choice
could also be driven by the degree of integration of the overall LNG chain if it is easier to
finance each phase of the project vs. a single large scale financing.
The credit rating of sponsors has an effect on the financing of large complex projects.
If financing involves too many financial institutions, it might be easier for each partner to
raise its individual share of the project. On the other hand, some partners may be unable
to raise the money for the project against their own assets and would prefer to jointly
finance the project.
A risk factor of 1 →
well established partners with superior credit ratings
A risk factor of 5 →
a myriad of partners including those with sub-par credit
LNG sales agreements are quite complex and secretive. An SPA (sales and purchase
agreement) for a new project determines LNG revenues. This agreement also includes the
financial strength and reliability of the buyer. Long term contracts reduce market risk but
also reduce profitability during a time of rising natural gas prices. A pricing formula
based on natural gas price fluctuation has a different risk factor than a formula based on
oil prices, which historically showed less volatility before 2006. Strength of the
marketing entity to support market risk includes the ability to book contracts and terminal
capacity and the credit quality of the purchasing entity. Distance to markets and
competition with local gas or closer LNG sources require a netback economic model.
A risk factor of 1 →
several long term contracts with spot cargo capacity
A risk factor of 5 →
few short term contracts or questionable stability of buyer
The Project Lending Agreement defines debt service and creditors rights. These
agreements define the terms and conditions of financing and prevent the owners and
counter parties from changing the risks and preserving the liquidity and cash flow.
A risk factor of 1 →
familiar sponsors with good history
A risk factor of 5 →
new sponsors without established history
Technology, construction and operations are crucial to define dependability in
achieving the project goal. Investment grade credit will rely on the use of proven
technology and standard industry practice. These risks can be separated into ‘Preconstruction’ and ‘Post-construction’ risk. Pre-construction risk includes evaluating
proven technology in a similar project environment. Site and permitting (political) risk
with good public and government relations can mitigate opposition. The guarantees of the
contractor/licensor and their financial stability are contributing factors in this risk
category which impact the liquidated damage imposed on the contractor. In times of tight
resources, the availability of contractor personnel can be crucial to the success of the
project and its reliability.
Post-construction risk seeks assurance that the project will run successfully to
generate the revenues for debt service. By choosing proven technologies, experienced
contractors and capable operators, a degree of confidence can be achieved.
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A risk factor of 1 →contractors with proven local design and operating experience
A risk factor of 5 →new contractors without design experience or local knowledge
Competitive market exposure, relative to peers, is a principal credit criterion. Low
cost production relative to the market is essential for attracting the necessary capital. This
exposure includes access to a large amount of natural gas with little domestic demand,
which translates to higher long term profits from monetizing natural gas assets.
Competitiveness of the project is also influenced by the feed gas price, which includes
the stability of the reservoir owner and the predictability of the tax regime in the
producing country. The break even cost varies substantially among greenfield vs.
brownfield development, the train capacity, and marketable by-product revenues.
A risk factor of 1 →
high margin between product and netback price
A risk factor of 5 →
high production cost relative to market pricing
LNG, like natural gas, shows high price volatility throughout a year. Demand profiles
in targeted markets affect the ability to sustain continuous operation of a baseload plant.
Therefore, Pricing Variables are probably the greatest project risks affecting the ability to
sustain operation even if the LNG price would drop below a break-even threshold.
A risk factor of 1 →buyers in diverse markets balancing the overall demand profile
A risk factor of 5 →dedication to limited markets with annual demand fluctuations
Counter Party Exposure includes risk from participants such as the feedstock supplier,
LNG buyers, EPC contractors, ship constructors and government entities who provide the
willingness and ability to honor the obligation to the project.
A risk factor of 1 →
counter parties with strong balance sheets
A risk factor of 5 →
low credit assessment of the counter party
Other impacts on the project cost are taxes, import duties, and exchange rate
fluctuations. Export Credit Agency (ECA) financing requirements could cause the
purchase of materials in countries that may not have the lowest prices and exchange rate
fluctuations can cause unnecessary financial risk.
Several other factors enter into the overall risk assessment including:
•
Legal structure
•
Currency
•
Liquidity
•
Forecasting results
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Sovereign Risk. A country rating factor such as the “Coface Country Rating Factor”
gives an indication of security or territorial risk for the investment. The country risk
factor includes the local business environment, economic, and political issues. The
developed risk factor is between 0 and 1 in order to give the risk a numerical value. A
country such as Australia shows a very low factor of 0.0, while countries like Libya,
Indonesia, Yemen and Nigeria may have factors ranging from 0.8 and 1.0. Fiscal issues
by the host government will not turn an uneconomical project into a profitable
investment, but can improve the attractiveness for investors, which can be crucial during
times of scarce fund availability among competing projects.
Timely provision of permits for construction and operation by the host government
are important to expedite project development, since the time between incurring
expenditures and earning revenues can be long for a project of this magnitude.
In addition, country related factors that will impact the project include:
•
Duties and taxes (including tax holidays)
•
Local content for material and labor
•
Local rules and regulations (unions, training, and sustainability)
•
Political stability
Relative Institutional Risk. This risk addresses the existence of vital business and
legal institutions, or non-existence in emerging markets, which are not measured in
Standard & Poor’s sovereign country rating. These risks can be property rights and
commercial law adverse to investor’s experience, or lack of a legal basis for SPA’s as
collateral to lenders.
Results of the CAPM Model. The commercial risks are listed in a Financial Risk
Calculator with a value between 1 and 5. The factored summation is entered into the
CAPM to calculate an interest rate for debt and equity. A simplified version of this
calculation is provided in Table 7. The financing cost from Table 2 was based on using
low risk interest. The variation in specific cost due to financing a higher risk project is
presented in Table 8. The results show that the financing cost can range from 18 to 22%
of the total plant specific cost. The difference between a low and high risk project can
impact the financing cost similar to the site preparation sensitivity presented in Table 3.
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Table 7. Financial Risk Calculator Using CAPM Model
Project Level Risk
LNG sales agreement
Credit Rating of Sponsors
Shipping Contracts
Project lending agreement
LOW
HIGH
1
1
4
4
1
3
Technology, construction and operation
Technology, new or well proven
Contractor Experience
1
1
3
4
Competitive Market Exposure
Gas Reservoir
Competitive Projects and Markets
1
2
3
4
Pricing Variables
1
3
Counter Party Exposure
2
2
Legal Structure
Currency Risk
Liquidity Risk
Forecasting Risk
1
1
1
1
3
3
4
4
1
2
3
5
1
2
1.4
2.3
Sovereign Risk
General Country Rating
Taxes, Duties, and local content
Relative Institutional Risk
Beta (ß) =
E (Ri)
Expected Return of Capital Assets
Rf
Risk Free Interest
for example:
T-bill =
delta to T-bill +
3%
1%
Rm
Expected Return of Market
for example:
Rf plus
3%
Interest delta between equity and debt
4%
E (Ri)
LOW RISK CASE
EQUITY
DEBT
10%
90%
INTEREST OF EQUITY
INTEREST OF DEBT
12%
8%
HIGHER RISK CASE
EQUITY
DEBT
30%
70%
INTEREST OF EQUITY
INTEREST OF DEBT
15%
11%
= Rf + ß
(Rm
- Rf)
= 4% + 1.4
( 7% -
4% )
= 4% + 2.3
( 7% -
4% )
Table 8. Variation of Specific Plant Cost Based on the Cost of Financing
Plant 1
Plant 2
Plant 3
Plant 4
Plant 5
Plant 6
Mt/a
#
4.5
99
4.5
137
4.5
202
4.5
255
4.5
327
4.5
397
Base Financing Cost (Low Risk
Interest)
¢/t
37
45
56
67
80
95
Total Cost w/ Original Interest
¢/t
200
247
315
377
459
549
Revised Total Cost (Higher
Risk Interest)
¢/t
208
256
327
393
478
573
Production Rate
Equipment Count
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SUMMARY
Evaluating the success of an LNG liquefaction project is a difficult task. Historically,
LNG projects have proven to be reliable, profitable, safe, and challenging. However,
projects are inevitably compared by their overall cost and LNG capacity. Comparisons
using a specific cost metric, e.g. USD/ton of LNG do not give credit to the site specific
elements that make each project unique.
There are many elements that affect the project specific cost. The level of scope will
define the intensity of gas treatment, which affects the overall equipment count.
Fluctuations in the demand for premium materials will dictate the relative cost of
equipment. Although site preparation and LNG storage requirements are different for
every project, cost intensive marine systems are wholly customized for every location.
Sponsors and contractors each have their own contributions to suitably build the project,
but site specific labor is a strong cost driver for facilities in a remote location. Lastly, the
commercial issues of bringing together sponsors for multi-billion dollar projects results in
a cost of raising financing for such an important endeavor.
A redefined specific cost, based on a clear understanding of the scope of each project,
could be a suitable way to review complex projects in challenging locations. This paper
demonstrates that the cost for a plant can vary by 100% or more when site specific
conditions demand different considerations. As a result, it is clear that no two LNG
projects are created equal.
REFERENCES CITED
1.
C.A. Durr, F. F. de la Vega, The M. W. Kellogg Company, Cost Reduction in Major
LNG Facilities, 17th World Gas Conference, 5-9 June 1988.
2.
Charles Durr, David Coyle, Don Hill and Sharon Smith, KBR, LNG Technology for
the Commercially Minded, GasTech 2005, 14-17 March 2006.
3.
Sam Kumar, Chicago Bridge and Iron Company, Design and Construction of Above
Ground Tanks, Hydrocarbon Asia, July/August 2001.
4.
Charles Yost and Robert DiNapoli, Merlin Associates, LNG Plant Costs – Past and
Present Trends and a look at the Future, AIChE Spring Meeting, April 2005.
5.
Harry Audus, presented on behalf of Statoil, The Sleipner and Snøhvit CO2 Injection
Projects, Canadian CO2 Capture and Storage Technology Roadmap Workshop,
Calgary, Canada, 18-19 September, 2003.
6.
Rod Morrison, Thomson Financial, LNG Finance: Funding the Fuel of the 21st
Century, pfi-market intelligence, 2005.
7.
Gerald B. Greenwald, Klumer Law International, Ltd., Liquefied Natural Gas:
Developing and Financing International Energy Projects, 1998.
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