lng liquefaction—not all plants are created equal

7/27/2019 LNG LIQUEFACTIONNOT ALL PLANTS ARE CREATED EQUAL

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LNG LIQUEFACTIONNOT ALL PLANTS ARE CREATED EQUAL

Heinz KotzotSection Leader, LNG and Gas Processing

Charles Durr

Energy Technology

David CoyleTechnology Manager

Chris CaswellPrincipal Technical Professional

KBRHouston, Texas, [email protected]

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 intothe 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 abbreviatedas dollars per ton is highly dependent on site specific factors. These factors include theremote nature of the site, local content requirements, design criteria, marine conditions,design practices, and scope differences. The purpose of this paper is to discuss theimpact 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 allconditions are ideal, to establish a lowest cost LNG project. Individual site and scopespecific 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 specificcriteria, often imbedded in a project design basis, are more clearly defined byenumerating and quantifying the elements that differ from a low cost reference designwith a minimal scope. In addition to the technical analysis, a review of commercialissues is presented for the benefit of a technical audience. Commercial risks are enteredinto a capital asset pricing model to determine an additional project specific element of

each cost benchmark.


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INTRODUCTION

Building any multi-billion dollar project requires a well coordinated plan, alignedproject sponsors, and financial backing. The viability of such a project will be scrutinizedon 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 arenecessary 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 lowestcost 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 seldombecomes more influential than lowest capital cost. This paper will determine the majorcontributors to the cost of an LNG plant and why certain elements are necessary, whichadd a corresponding, and unavoidable, cost.

The specific cost of an LNG plant has become a fashionable metric to compareprojects against each other. This dollar per ton per year number, commonly referred to asdollars 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 thespecific cost as long as equipment sizes increase in a proportional manner (as opposed toadding one or more modules of equal capacity). In addition, variations in capital cost arestrongly affected by:

Plant location

Cost of labor

Feed gas composition

Product specification

Competition among contractors and liquefaction process technologies are oftenattributed as significant factors that affect specific cost. The cost impact of technologyselection is not as significant as often portrayed in the total project cost, but technologywill impact the operation, availability, and efficiency of the plant. With equal conditionsamong 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 ismainly a function of site related conditions, project development, and project executionobjectives. Capital cost reduction must be balanced with other important objectives, suchas safety, reliability, and operation and maintenance practices.


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Gas FieldLiquefaction

Plant LNG St orage Tank

LNG Tanker

LNG Sto rage Tank

VaporizersVaporizers

PRODUCING REGION CONSUMING REGIONTRANSPORTATION

Gas FieldLiquefaction

Plant LNG St orage Tank

LNG Tanker

LNG Sto rage Tank

VaporizersVaporizers

PRODUCING REGION CONSUMING REGIONTRANSPORTATION

For this paper, a base production rate of 4.5 Mt/a (million tons per year) of LNG ischosen to allow fair comparisons without distortion due to economy of scale. In theanalysis, this paper addresses only the LNG liquefaction portion of the LNG value chain,as highlighted in Figure 1.

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. Commercialconsiderations, which are presented for a technical audience, are included in this paper toshow the significant impact on the overall cost of an LNG project.

As the global market for LNG has developed, financing has always required carefulplanning and is becoming increasingly complex. Aspects to be considered includeproject rate of return, long-term demand, political and regulatory stability, productioncovered by take-or-pay arrangements, risk allocation among the sponsors, thecreditworthiness of the buyers and the availability of security or guarantees.

This paper will attempt to quantify these technical and commercial influences in order todevelop transparency in regard to LNG specific cost.

TECHNICAL

The primary drivers for the capital cost of an LNG liquefaction facility are sitespecific 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 thedesign 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 foundin 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 andmarket 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 DistributionPercentage of

Total Cost

Gas Treating 7

Fractionation 3

Liquefaction 28

Refrigeration 14

Utilities 20

Offsites (storage, loading, flare) 27Site preparation 1

Total 100

While this information may be of interest, the table does not provide insight as towhat 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 costof 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 impactson plant specific cost.

Alternative Cost Distribution

Instead of evaluating the total plant cost by process area, this paper will present theplant cost in five major categories: material related cost, location related cost, sponsor &contractor cost, labor cost, and financing cost. Defining overall plant cost within theseareas will allow for cost sensitivity analysis of project specific items, and how stronglythey influence the cost metric.

Material Related Cost. This cost component includes all tagged equipment andauxiliary material, including bulks (e.g. piping, electrical, structural steel, concrete, etc.).Material costs can vary substantially from historical norms depending on the technicalrequirements 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 andlocation. This cost is also dependent on the plant size. A separate sensitivity analysis willshow the cost effects for different degrees of site preparation work. LNG storage tanksare not a strong function of plant production rate, but depend on ship size and loadingfrequency. Similarly, the cost of marine facilities is largely independent of plant capacityand 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 ownerspersonnel used during project development and items such as legal, permitting, etc. Thecost for the owners personnel is commonly estimated as 10% of total plant cost. Thecontractor cost includes engineering, construction management, and other related costs.

Labor Cost. This cost element consists of the labor cost at the plant location, whichis commonly identified as a subcontract cost. Although this cost includes somematerial related items such as paint and insulation, the vast majority of this componentcovers the workhour cost for erecting the plant.

Financing Cost. The financing cost includes the interest on equity and debt, as wellas the operating capital necessary for the initial phases of the project until LNG revenueswill cover operating costs. This cost is seldom included in the evaluation of the specificcost 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 Costproject. This commercial outcome is the most desirable goal for any project. However, asthe CAPEX is the largest single component of the life-cycle cost and to avoid thecomplications 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 aproject, such as adding equipment, modifying labor cost and efficiency, or adjusting thecost of capital based on risk assessment. Results from this model will be presented for avariety 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 allowseasy comparison from one design with known parameters to another with assumed (orknown) differences.

Plant Configurations

The primary factors that set the plant configuration are:

Feed gas composition and conditions that establish the gas treating and NGLrecovery

LNG Product Specifications, which control the severity of NGL recovery andnitrogen rejection

The pictograph in Figure 2 illustrates the elements of feed gas treating that could berequired for any LNG project and the corresponding shrinkage of the available feed gas toachieve the targeted LNG capacity. Higher levels of NGL recovery may be driven by theoverall product economics; i.e. if the value of LPG exceeds the value of incrementalLNG. Although deep NGL recovery can improve the revenue stream and life-cycle costfor the entire project, it will increase the metric when evaluating LNG specific cost.


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Maximum Treating Plant

Fuel Gas NGL

Nitrogen

Removal Boil Off

Liquid Slug

Removal

Condensate

Stabilization

Acid Gas

Removal

Water

Removal

10

0% `

70-80%

LNG

Plant

Feed

Figure 2. Maximum Feed Gas Treating and the Effect on LNG Production

In order to develop proper cost comparisons for different project configurations, theanalysis will keep the following items constant:

Production rate of 4.5 Mt/a of LNG

95% plant availability

Average ambient temperature of 22C.

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 productspecifications, 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 ofequipment items that would be required for such an LNG project. This scenario could beachieved by the presence of an existing upstream LPG recovery plant. Figure 3 illustratesthis base scenario.

Minimum Treating Plant

Fuel Gas Boil Off

100%

95%

LNG

Plant

Feed

Figure 3. Plant 1 Minimum Feed Gas Treating

The base plant will require a minimal scope for utilities and offsite facilities. Thisscope would include LNG storage tanks, a jetty with loading equipment, relief systems,fire protection, and the storage of imported refrigerant. This scheme could be developedif 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.


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Utilities

Pro

cessTrain

Offsites

Inlet

Liquefaction

Propane

Refrigeration MR Refrigeration

Product

Storage

Flare & Liquid

Burner

Refrigerant

StorageLoading

Fire

Protection

Shipping

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 atvarious locations. Plant 1 results in a small LNG plant, where utilities that are importedresult in an increase in operating costs for a minimum capital cost. This scenario can beachieved by upstream feed gas treating (reflected in feed gas price) with imported utilitiesadding to operating expenses instead of capital investment. The plant will be increased insize, adding treating and processing units, up to the maximum (Plant 6), as shown inFigure 5.

Utilities

Offsites

ProcessTrain

Inlet Stabilization AGRUDehydration

& Mercury

Removal

LiquefactionFractionationPropane

Refrig.MR Refrig .

Product

Storage

Flare & Liq.

BurnerRefrigerant

Sto ra e

Loading

Inhibitor

Recovery

SRU & AG

Enrichment

Power

GenerationFuel Gas

Heat

Medium

Diesel

Storage

Air &

Nitrogen

Sea Water Fresh Water BFW/Steam/

Condensate

Waste Water

Effluents

Fire

Protection

Slugcatcher

Shipping

AG Disposal

Figure 5. Plant 6 Maximum Number of Units in LNG Facility


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Outlining the Six Design Cases

Plant 1, illustrated in Figure 4, includes only the process units that are required forliquefaction. Feed gas arriving at the plant boundary limit is expected to be ready forliquefaction. 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 includeonly LNG storage and the loading system.

Plant 2 includes all items in Plant 1 plus all utility systems while Plant 3 will includeall of the items in Plant 2 with the addition offeed gas treatment units. The treatmentsystems included in Plant 3 are acid gas removal (AGRU), dehydration, and mercuryremoval.

Plant 4 will add afractionation unit to Plant 3. The presence of a fractionation unitincludes additional equipment forLPG storage and loading.

Plant 5 will add extensive feed gas treating facilities to Plant 4. These facilitiesinclude a slug catcher, condensate stabilization, and the provision for high CO2extraction within the AGRU. As a result of the high CO2 extraction, there will beaccommodation forCO2 sequestering.

Plant 6 will add a sulfur recovery unit (SRU) to Plant 5 and provide formaximumLPG recovery within the process unit. An overview of the units for Plant 6 is illustratedin Figure 5.

The comparison of the six cases will highlight the effects of site specific criteria onthe 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 ispresented in Table 2. The metric is shown as an internally developed currency perannual ton, abbreviated as /t. This currency unit can be used to allow comparisonamong 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

Production Rate Mt/a 4.5 4.5 4.5 4.5 4.5 4.5

Equipment Count # 99 137 202 255 327 397

Cost of Material /t 38 50 61 69 86 110

Site Preparation /t 2 3 4 5 7 8

Tanks /t 17 17 17 22 22 22

Marine Facilities /t 26 26 26 26 26 26

Sponsor & Contractor Cost /t 41 53 74 91 114 138

Labor Cost /t 39 53 77 97 124 150

Financing Cost /t 37 45 56 67 80 95

315 377 459 549Total Cost at Startup /t 200 247


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Changes to an individual cost item, such as site preparation, will affect other costelements of the table. Therefore, an increase of the site preparation cost will have agreater effect on the total cost than the basic change of cost in that row. The sensitivityanalysis in the following paragraphs will show the overall effect on the total cost as afunction 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 ofmaterial will increase. However, the relative increase in equipment cost over the sixconfigurations 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 affectcomparisons of specific cost among LNG projects as the material market has outpacedeconomy of scale benefits over recent years.

Site Preparation. The required plot area will increase as a function of the totalequipment count. Therefore, the cost for site preparation increases, from Plant 1 throughPlant 6, with the incremental scope added to each plant. In Table 2, basic site preparationcost is included in the calculation, which requires some earth movement-type work foreach example. Table 3 illustrates the relative impact of a less advantageous jobsite whichcould significantly increase the site preparation cost and contribute to the increase inoverall cost.

Table 3. Variation of Specific Plant Cost Based on Enhanced Site Preparation



Equipment Count # 99 137 202 255 327 397

Base Site Preparation Cost /t 2 3 4 5 7 8

335 404 493 592Revised Total Cost w /

Enhanced Site Preparation /t 210 261

315 377 459 549Total Cost w/ Original Site

Preparation/t 200 247

Tanks. Although many plants have used single containment (SC) tanks over thelast 40 years, the trend is now toward the use of full containment (FC) tanks. Fullcontainment tanks reduce the plot space required for LNG storage, but increase the tankcost as much as 70% [3]. In addition to increasing the cost, FC tanks require a longerconstruction time, which may have a cost impact on the schedule. The LNG storage tankcost does not vary in our constant capacity analysis, but cost differences could arise dueto varying soil and seismic site conditions. For the analysis in this paper, site deviationsfor 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 locationswith less favorable conditions than those in major population centers. To reach a sea bedclearance of at least 13.5 m, the jetty head needs to be located far enough offshore ordredging will be required. Some locations may also require a breakwater (i.e. a physicalwave 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 processconfiguration and plant capacity, unless a second berth is required to offload a high plantcapacity. For the 4.5 Mt/a facility, a 700 m long jetty trestle and a breakwater wasconsidered.

The jetty consists of two major sections, the jetty head and the trestle. Theconstruction of the jetty head, consisting of breasting dolphins, mooring dolphins, andgangways, will vary little from site to site. The trestle cost is primarily dependent on itslength and sub-sea soil conditions, which will affect both the structure and the LNGloading lines. If the jetty head needs to be moved further offshore, the trestle length willincrease 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 jettytrestle, 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



Equipment Count # 99 137 202 255 327 397

Base Marine Facility Cost /t 26 26 26 26 26 26

315 377 459 549

Total Cost w/ Original Marine

Facilities /t 200 247

Revised Total Cost w/

Enhanced Marine Facilities/t 218 265 333 395 477 567

Sponsor and Contractor Cost. For this paper, the cost for the sponsors is kept at aconstant ratio of the total plant cost, but could vary for issues such as permitting and legalcosts. As each plant requires additional scope, the sponsor costs will increase due to theadded complexity. The contractor cost is a function of the scope of work and the projectlocation, and is determined in proportion to the number of equipment items. Thecontractor cost includes home office services, construction management, construction

equipment and temporary facilities. Business expenses that are not part of the othercategories 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 projectlocation. With labor costs accounting for up to 50% of the cost of construction, theimpact of labor has to be considered separately from the cost of equipment. Thedifference 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) whichwill 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



Equipment Count # 99 137 202 255 327 397

Base Labor Cost /t 39 53 77 97 124 150

391 475 583 701Revised Total Cost w/ Higher

Labor Cost/t 239 299

315 377 459 549Total Cost w/ Original Labor /t 200 247

Financing Cost. The cost of financing, i.e. the interest required for equity and debtduring project development, will vary according to the risk and availability of capital fora specific project. Due to the complex nature of project financing, this subject isaddressed 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 traditionalconstruction, 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 theproject execution plan. Modular design allows the manufacture of sections of the plant atspecialized industrial fabrication yards, and is commonly used in the design of topsidesfor offshore projects. This approach is intended to relocate construction labor and reduce

the magnitude of site-specific construction costs. Modular design allows parallelconstruction paths, but can add schedule risk if shipping the modules has to occur withina small window of favorable weather conditions. In general, there is no cost advantage tomodular design. Commonly, more structural steel and engineering is required than for astick-built plant, but a modular design could mitigate the escalating costs anticipated for achallenging or remote location.

Environmental Issues. Project costs influenced by environmental issues mainlyaddress plant emissions. Guidelines from the World Bank are commonly applied for NOxemissions, which determine the limits on gas turbine exhaust and required mitigatingcontrols. 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 theatmosphere, 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 gasenrichment unit upstream of the SRU. In environmentally conscientious areas, projectsmay require CO2 sequestering, which results in extensive acid gas handling for re-injection into a nearby deep reservoir. For Snhvit LNG, Statoil estimated an investmentcost of 190 million US$ for CO2 sequestering alone, which includes compression anddrying facilities [5].


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Process Operation. Many papers and presentations have discussed the impact onCAPEX, 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 basicissue 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 impacton the production is relatively minor. In areas with a larger ambient temperaturefluctuation, 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 ofthe year; if sized for a higher ambient temperature, the equipment will be constrained formost of the year. Finding the right balance is a challenge for the designer, if the plantcapacity is not dictated by marketing.

For the same plant configuration, relocating the plants to a site with a 5 C highertemperature profile will decrease the plant production by approximately 4 %. Due to thedecrease 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 designtemperature.

Table 6. Variation of Specific Plant Cost Based on Higher Ambient Temperature


Original Production rate Mt/a 4.5 4.5 4.5 4.5 4.5 4.5

Reduced Production Rate Mt/a 4.3 4.3 4.3 4.3 4.3 4.3

Original Total Cost at Startup /t 200 247 315 377 459 549

Rev ised Total Cost at Star tup /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 andthe 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 ofthis 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 thehost country, or other costs passed through to the bottom line. Some of these issuesinclude client or regional specifications, taxes and import duties, local contentrequirements (e.g. training), and local infrastructure development.


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COMMERCIAL

The following section regarding commercial issues is presented for the benefit of atechnical audience. The concepts are comprehensive enough to support the evaluation ofLNG 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 aninvestment grade project. With the cost of funding varying significantly with thecommercial risk, financing will contribute to a plants specific cost. These commercialrisks are based on facts and conditions specific to the locations along the entire LNGchain and the strengths of the sponsoring parties. Items that are considered bycommercial 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 andaddress 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 ofthe financing companies, but the model illustrates the decision process and is meant toinject some transparency into the complexity of financing.

Equity and Debt

The equity portion of a project can vary significantly. If the projects sponsors choosea 100% equity arrangement, they can avoid complex financing issues; however, theimmense cost of an LNG project will impact the balance sheet of even the largestcompany, requiring most projects to seek outside financing. Since the interest required forequity 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 equityportion 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, financialinstitutions and analysts in extensive negotiations to ensure each member can assure awin-win situation to their stakeholders. For example, a low risk project might qualify fora 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 sponsorsmight even have some obligations beyond their equity obligations, such as a completionguarantee 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 manypublications that discuss the issues to be considered; however, it is difficult to clearlydetermine 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 PricingModel) to quantify risk. For each risk element we assign a risk factor between 1 (lowrisk) and 5 (high risk). These individual factors are combined in a factored summation() which will be entered into the following CAPM formula:

E ( R i ) = R f + ( R m - R f)

or

E(rate of return) = R(risk free interest) + ( 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 FreeInterest of 4 % and an Expected Return of Market of 7%, the factor will bedetermined for two projects with opposite risk profiles. The results of these calculationsare included at the end of this section.

Thomson Financial, which sponsored the pfi market intelligence publicationLNGFinance: 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 willonly highlight the major issues.

Project Level Risk. Project level risk addresses the contractual foundation thatprotects the investors from market, operating and ownership risk for assurance ofrepayment. In essence, the project and local law will give investors the security of theentire projects assets. Financial leverage is used to find common ground for multi-sponsor 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. Thechoice 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 choicecould also be driven by the degree of integration of the overall LNG chain if it is easier tofinance 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 toraise its individual share of the project. On the other hand, some partners may be unableto raise the money for the project against their own assets and would prefer to jointlyfinance 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 purchaseagreement) 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 butalso reduce profitability during a time of rising natural gas prices. A pricing formulabased on natural gas price fluctuation has a different risk factor than a formula based onoil prices, which historically showed less volatility before 2006. Strength of themarketing entity to support market risk includes the ability to book contracts and terminalcapacity and the credit quality of the purchasing entity. Distance to markets andcompetition 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. Theseagreements define the terms and conditions of financing and prevent the owners andcounter 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 inachieving the project goal. Investment grade credit will rely on the use of proventechnology and standard industry practice. These risks can be separated into Pre-

construction and Post-construction risk. Pre-construction risk includes evaluatingproven technology in a similar project environment. Site and permitting (political) riskwith good public and government relations can mitigate opposition. The guarantees of thecontractor/licensor and their financial stability are contributing factors in this riskcategory which impact the liquidated damage imposed on the contractor. In times of tightresources, 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 togenerate the revenues for debt service. By choosing proven technologies, experiencedcontractors 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. Lowcost production relative to the market is essential for attracting the necessary capital. Thisexposure 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 includesthe 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 profilesin 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 tosustain 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 thewillingness 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 ratefluctuations. Export Credit Agency (ECA) financing requirements could cause the

purchase of materials in countries that may not have the lowest prices and exchange ratefluctuations 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 Factorgives an indication of security or territorial risk for the investment. The country riskfactor includes the local business environment, economic, and political issues. Thedeveloped risk factor is between 0 and 1 in order to give the risk a numerical value. Acountry 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 issuesby the host government will not turn an uneconomical project into a profitableinvestment, but can improve the attractiveness for investors, which can be crucial duringtimes of scarce fund availability among competing projects.

Timely provision of permits for construction and operation by the host governmentare important to expedite project development, since the time between incurringexpenditures 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 andlegal institutions, or non-existence in emerging markets, which are not measured inStandard & Poors sovereign country rating. These risks can be property rights andcommercial law adverse to investors experience, or lack of a legal basis for SPAs ascollateral to lenders.

Results of the CAPM Model. The commercial risks are listed in a Financial RiskCalculator with a value between 1 and 5. The factored summation is entered into theCAPM to calculate an interest rate for debt and equity. A simplified version of thiscalculation is provided in Table 7. The financing cost from Table 2 was based on usinglow 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 canimpact 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 LOW HIGH

LNG sales agreement Credit Rating of Sponsors 1 4

Shipping Contracts 1 4

Project lending agreement 1 3

Technology, construction and operation Technology, new or well proven 1 3

Contractor Experience 1 4

Competitive Market Exposure Gas Reservoir 1 3

Competitive Projects and Markets 2 4

Pricing Variables 1 3

Counter Party Exposure 2 2

Legal Structure 1 3

Currency Risk 1 3

Liquidity Risk 1 4

Forecasting Risk 1 4

Sovereign Risk General Country Rating 1 3Taxes, Duties, and local content 2 5

Relative Institutional Risk 1 2

Beta () = 1.4 2.3

E (Ri) Expected Return of Capital Assets

T-bill = 3%

Rf Risk Free Interest for example: delta to T-bill + 1%

Rm Expected Return of Market for example: Rf plus 3%

Interest delta between equity and debt 4%

E (Ri) = Rf + (Rm - Rf)

LOW RISK CASE

EQUITY 10%

DEBT 90%

INTEREST OF EQUITY 12%

INTEREST OF DEBT 8% = 4% + 1.4 ( 7% - 4% )

HIGHER RISK CASE

EQUITY 30%

DEBT 70%

INTEREST OF EQUITY 15%

INTEREST OF DEBT 11% = 4% + 2.3 ( 7% - 4% )

Table 8. Variation of Specific Plant Cost Based on the Cost of Financing



Equipment Count # 99 137 202 255 327 397

Base Financing Cost (Low Risk

Interest)/t 37 45 56 67 80 95

327 393 478 573Revised Total Cost (Higher

Risk Interest)

/t 208 256

315 377 459 549Total Cost w/ Original Interest /t 200 247


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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 specificelements that make each project unique.

There are many elements that affect the project specific cost. The level of scope willdefine the intensity of gas treatment, which affects the overall equipment count.Fluctuations in the demand for premium materials will dictate the relative cost ofequipment. Although site preparation and LNG storage requirements are different forevery 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, thecommercial 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 paperdemonstrates that the cost for a plant can vary by 100% or more when site specificconditions 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 MajorLNG Facilities, 17th World Gas Conference, 5-9 June 1988.

2. Charles Durr, David Coyle, Don Hill and Sharon Smith, KBR,LNG Technology forthe Commercially Minded, GasTech 2005, 14-17 March 2006.

3. Sam Kumar, Chicago Bridge and Iron Company,Design and Construction of AboveGround 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 Snhvit CO2 InjectionProjects, 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 21stCentury, pfi-market intelligence, 2005.

7. Gerald B. Greenwald, Klumer Law International, Ltd., Liquefied Natural Gas:Developing and Financing International Energy Projects, 1998.

lng liquefaction—not all plants are created equal

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