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SPE 120745

Economics of LNG Projects

Faleh T. Al- Saadoon and Abel U Nsa

Texas A&M U.-Kingsville, Kingsville, Texas

Copyright 2009, Society of Petroleum Engineers

This paper was prepared for presentation at the 2009 SPE P roduction and Operations Symposium held in Oklahoma City, Oklahoma, USA, 4–8 April 2009.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without thewritten consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words;illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

The economic viability of a liquefied natural gas (LNG) project is evaluated usingindustry-wide data. The range of expenditure figures (both capital and operating)obtained from the literature is synchronized into a unit energy basis across the valuechain – liquefaction, shipping and re-gasification.

A Base Case is adopted based on a single train of 4.2 million metric ton per annum(MMTPA) capacity for a round-trip distance of 6200 miles (from Nigeria to the U.S. GulfCoast), taking one (1) month round-trip voyage. It is assumed that the plant requires a 4-year construction period and it operates for 350 days a year in evaluating the economicsof the project.

Two measures of profitability are used in assessing the economic viability of theLNG project, namely rate of return (ROR) and undiscounted pay-out-time (POT). A BaseCase is performed using a Base Case Capital Expenditure (Base Case CAPEX), 15%discount rate and 3.00$/MMBtu raw gas price. In addition, sensitivity analyses arecarried out on CAPEX (using -20%, -10%, Base Case CAPEX, +10%, and +20%), ondiscount rates (using 10%, 15%, 20% and 25%), on raw gas prices (using 1.00, 2.00,3.00, 4.00, and 5.00$/MMBtu) and on overall operating expenditures (OPEX) ranging between 4.7% and 14.7% of CAPEX.

The pay-out-times for the various scenarios considered at discount rates of 10, 15,20 and 25% are 7.82, 5.18, 3.68 and 2.76 years after startup/commissioning, respectively.

The break-even prices range between 3.00$/MMBtu (at Base Case CAPEX less20%, 10% discount rate and 1.00$/MMBtu raw gas price) and 12.10$/MMBtu (at Base

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Case CAPEX plus 20%, 25% discount rate and 5.00$/MMBtu raw gas price). Thecorresponding mark-ups range between 2.00 and 7.15$/MMBtu, respectively.

The break-even and mark-up prices increase linearly with increasing raw gas pricesyielding slopes of 1.17 and 0.17, respectively. These relationships hold true with all 100cases considered in the sensitivity analysis.

A general survey of LNG liquefaction processes is also included.

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Introduction

LNG is one of the monetization options for natural gas; others include pipeline and thegas-to-liquid (GTL) option. The preferred option is determined mainly by its proximityto the (consuming) market and by its location.

The pipeline option involves the construction of a large diameter low/high pressure pipeline to transport the pipeline quality natural gas to the market. The GTL optioninvolves the conversion of natural gas into a stable liquid using the Fischer-Tropsch (FT) process and then transporting the refined products (diesel and naphtha) by conventionalmeans to the market.

The LNG option involves the physical conversion of the natural gas into liquid usingcryogenic (low temperature) conditions, transporting the LNG to the market by speciallydesigned ocean-going tankers and then re-gasifying the LNG into gas.

The pipeline option becomes less viable as the distance between the source and themarket increases and/or the resource environment becomes harsher. It is obvious fromFigure 1 that the cost of the pipeline option is higher than the LNG option when the

distance is in excess of 2200 miles (over 3500 km) in an onshore environment and inexcess of about 850 miles (about 1300 km) in an offshore environment (Rowe 2004).In addition to the long distance, difficult terrains as well as stranded gas development

also play a major role in adopting the LNG option. The focus of this work is on the“Economics of LNG Projects”.

Figure1 - Gas Transportation Cost (Rowe 2004)

LNG Value Chain

A conventional LNG project involves bringing together four (sometimes five)interdependent activities to connect the gas producer to the end user in what is called theLNG value/supply chain. These activities consist of: exploration and production (E&P),gas gathering (i.e. trunk lines), liquefaction, shipping and re-gasification. The gastransmission/gas gathering phase by means of trunk lines to deliver the produced gas

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from the remote fields to the liquefaction plant is sometimes lumped with the (E&P) phase to reduce the value chain to four.

I. Exploration and Production

This is the primary link in the value chain which involves all development activities -

exploration, drilling/ completion, field development, etc, prior to the liquefaction process.The proven reserve base must be sufficient to support the project. The delivery of 1million tones of LNG per annum for 20 years is equivalent to about 1 TCF (28 BCM) ofnatural gas. After taking into account the gas consumed and lost in the LNG supplychain (generally between 10% and 15%) and the reserve that must be left in the field atthe end of the project life to maintain production at the plateau level, a world-scale LNG project with a capacity of around 8 MMTPA (sufficient for two large trains), requires aminimum of around 10 TCF (280 BCM) of proven gas reserves (Flower 2004).

Another important economic consideration is to minimize process shutdowns whenassociated gas fields are used as project backups. Gas composition is another majorconsideration as revenues could also be generated from the natural gas liquids (NGL)

extracted during the liquefaction process.

II. LNG Liquefaction

The liquefaction process typically follows a three-step process: removal of impurities andrecovery of natural gas liquids (NGLs), liquefaction of methane via refrigeration,movement of the LNG to storage and finally to the tanker.

III. Shipping

LNG Tankers provide the link between the seller and the buyer. These are double-walledspecial purpose vessels designed and insulated to prevent rupture in case of an accidentduring ocean transportation. The LNG is kept at a cryogenic temperature of -256

0F

(1600C) and atmospheric pressure as a result of the insulation around the tanks.Approximately 0.1% to 0.15% of the cargo boils off each day and in the process helps tokeep the temperature of the remaining cargo stable.

IV. Re-gasification

Receiving terminals provide facilities to return the liquefied natural gas to it gaseousstate. This is achieved by pumping the LNG at atmospheric pressure to a double-walledstorage tank, until when needed. After which the LNG is further pumped at higher pressure through various receiving terminal components where it is warmed in acontrolled environment by passage through pipes heated by direct-fired heaters, orthrough pipes that are in heated water. The re-gasified natural gas is then regulated for pressure and finally sent into distribution pipelines for consumption.

Liquefaction Technologies

The liquefaction section of the LNG plant is the most significant section of the plant andaccount for about 30 – 40% of the capital cost of the overall plant. Key equipment itemsinclude the compressors used to circulate the refrigerants, the compressor drivers and the

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heat exchangers used to cool and liquefy the gas and exchange heat between therefrigerants. (Shukri 2004).

The liquefaction process is the transfer of sensible and latent heat and is achieved bystaged mechanical refrigeration, and compressing/expanding the gas, using turbo-expanders. The basic principles for cooling and liquefying the gas using refrigerants

involve matching as closely as possible the cooling/heating curves of the process gas andthat of the refrigerant. These principles result in a more efficient thermodynamic processrequiring less power per unit of LNG produced and they apply to all liquefaction processes.

Figure 2 presents a typical cooling curve for a liquefaction process showing threecooling zones: a pre-cooling zone, followed by a liquefaction zone and finally sub-cooling zone. All of these zones are characterized by having different curve slopes, orspecific heats, along the process. All of the LNG processes are designed by trying toapproach the cooling curve of the gas being liquefied, by using the specially mixed multi-

component refrigerants (MR) that will match the cooling curve at different zones/stagesof the liquefaction process to achieve high refrigeration efficiency and thereby reduceenergy consumption (Mokhatab, et al 2006).

Figure 2 - Typical Natural Gas/ Refrigerant Cooling Curve (Mokhatab et al, 2006)

Licensed Process Technologies

Various licensed liquefaction processes have been developed and used extensivelyaround the world with the major differences in the plants being the refrigeration cycles

involved. Some of the companies involved in the development and licensing of LNGliquefaction technology include Air Products & Chemicals Int. (APCI), Conoco-Philips,Marathon-Philips, Black& Veach, Shell and Linde-Statoil.Table 1 provides a summary of some of the competing technologies used by variouscompanies. The total number of base load LNG liquefaction trains running and underconstruction amounted to about 66 and 17, respectively. (as of Nov. 2004) in about 19LNG liquefaction plants. It is also very evident from Table 1 that the APCI Propane Pre-cooled Mixed Refrigerant (C3MR or PPMR) is the most dominant accounting for about

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77% of the total number of trains running and under construction, followed by theConoco-Phillips Optimized Cascade process accounting for about 9%.Table 2 provides a summary of the advantages and disadvantages of the variouscomponents and fluid refrigerants used in the various LNG liquefaction processes. Itshould be noted that the APCI process utilizes a small diameter wound tube bundles heat

exchangers (to provide very close temperature approaches), a mixed refrigerant (amixture of nitrogen, methane, ethane and propane), centrifugal compressors (for high pressure stage) and axial compressors (for low pressure stage). In the Phillips OptimizedCascade LNG Process (POCLP), aluminum and core-in-kettle heat exchangers, purerefrigerants (propane, ethylene and methane) and many compressors/turbine packages areused.

Economics of LNG Projects.

I. Capital Expenditures (CAPEX):

The CAPEX of LNG projects is estimated to be between $1.32/MMBtu and

$7.21/MMBtu depending on several factors, including type of technology used,greenfield or expansion projects, shipping distance between the liquefaction plant and re-gasification facility, economies of scale, learning curve improvement, and localinfrastructure availability.

In contrast, published data on the CAPEX of LNG projects shows a range of$200/TPA ($3.35/MMBtu) for BP’s project in Trinidad to > $850 /TPA($16.35/MMBtu). The latter reference (and thereby the CAPEX figure of $850/TPA) isdismissed as being an outlier (zealous) effort to magnify the potential benefit ofcompressed natural gas (CNG) over LNG (Subero et al. 2004)

Patel (Patel 2005) provided realistic CAPEX data for the following LNG projects:Qatargas, Nigeria LNG, Atlantic LNG, Rasgas and Oman LNG as being 375, 275, 230,

210, 200 $/TPA ( $7.21, $5.29, $4.23, $4.03, $3.85/MMBtu). Jenson (Jensen 2004) alsoquantifies the impact of shipping distances on the CAPEX for LNG projects in Trinidad, Nigeria and Qatar as being $2.00, $2.50 and $2.00/MMBtu respectively.

Similarly, (Coyle et al, 2003) cited references from Merlin Associates that estimatedthe costs of recent LNG plants to be in the range of 200 to 400 $/tonne/year (3.85 to 7.69$/MMBtu/year). They also provided costs figures contributed by the individual valuechains to include: 1.5 to $2.0/MMBtu (liquefaction), 0.5 to $1.2/MMBtu (shipping) and0.3 to $0.4/MMBtu (re-gasification).

II. Annual Operating Expenditures (OPEX):

Liquefaction fuel, re-gasification fuels and tanker boil-off contribute significantly to theoperating cost of the LNG projects. It should be noted that value is added to the gas as itgoes from one value chain to the other, another major influence is the location of the buyer and the seller, (Kellas 2003), reported shipping costs to the US or Europe to range between $0.6/MMBtu and $1.75/MMBtu for existing and potential Latin American,African and Middle Eastern LNG projects. Data tables for Approximate Spot LNGfreight rates from Commercials Services Company have also been generated with voyagedistance as major contributor to the costs; factors used are: tanker size (138,000 cm),speed (19 knots), rate $29,000 per day and boil-off (0.15% per day).

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Heren LNG Markets has also estimated the shipping cost from Bonny, Nigeria andLake Charles, USA to be $1.15/ MMBtu. In contrast, (Coyle et al, 2003) provided fuelloss as percentage of the feed gas across the value chain to be between 8 – 10% forliquefaction, 2 – 2.5% for re-gasification while shipping depends on the distance traveled.However, (Avellanet et al, 1998) reported LNG costs to be 7% of the cumulative

investment.Jensen (personal communication) estimates the liquefaction OPEX to be$0.2/MMBtu and 9% fuel consumption (raw gas), the shipping OPEX to be 3.6% ofCAPEX and 0.17% boil-off per day (LNG) and re-gasification OPEX to be 2.5% ofCAPEX and a fuel consumption of 2.5% of LNG.

III. Net Cash Flow (NCF) of LNG Projects:

The two measures used to assess the economic viability and profitability of LNG projectsare rate of return (ROR) and undiscounted pay-out time (POT). ROR is the discount rateat which the net present value is equal to zero. The undiscounted POT is the timerequired in years, after the commissioning (start-up) of the project, to pay back the

undiscounted initial investment.Discount rates of 10, 15, 20 and 25% along with raw gas prices of $1, $2, $3, $4 and

$5/MMBtu are used to determine the break-even prices and subsequently the markuprates for the various parameters evaluated.

The following parameters are assumed in the analysis of an LNG project:

● LNG plant is located in Nigeria● Re-gasification plant is located on the US Gulf Coast (USGC)● 350 days of plant operation per year (i.e. a Stream Factor of 96%)

• 4 years construction period

• 25 years plant life (after start-up)• 12 trips is made a year between Nigeria and the USGC (i.e. one-month round trip

voyage)

• Discount rates of 10, 15, 20 and 25%

• Raw gas prices of 1, 2, 3, 4 and $5/MMBtu

The CAPEX and OPEX of the Base Case are determined using Jenson’s estimates(personal communication) and are as follows:

Liquefaction: – CAPEX: $350 million, for infrastructure (Greenfield facility), plus $250

per ton of capacity for a train size of 4.2 MMTPA – OPEX: $0.20/MMBtu and fuel consumption of 9% of raw gas

Shipping: – CAPEX: $180 million for 135,000 cubic meter tanker, – OPEX 3.6% of CAPEX and 0.17% of boil-off (LNG) per day

Re-gasification: – CAPEX: $575 million for 850 MMCF/day facility, – OPEX:2.5% of CAPEX and fuel consumption of 2.5% of LNG

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The Base Case also assumes a raw gas price of $3/MMBtu and a discount rate of 15%.

Calculations of the break-even prices, POT and markup rates are also made by varyingthe Base Case data as follows:

• 10% increase in Base Case CAPEX• 20% increase in Base Case CAPEX

• 10% decrease in Base Case CAPEX

• 20% decrease in Base Case CAPEX

IV. Sensitivity Analysis:

The Base Case data collated is unitized in energy terms on an annual MMBtu basis byusing the appropriate conversions:

• Liquefaction CAPEX :

Base Case CAPEX is based on a $350 million for infra-structure plus $250.00 permetric ton for a train of 4.2 MMTPA.

MMBtu/41.6$52*10*2.4

)10*2.4*250()10*350(6

66

=+

based on a capacity of 4.2 MMTPA.

Where 1 ton ≈ 52 MMBtu

● Shipping CAPEX:Base Case CAPEX is based on a $180 million for 135,000 cubic meter capacitytanker making 12 round-trip voyages per year.

MMBtu/65.4$

9.23*12*135000

)10*180( 6

=

Where 1 cubic meter = 23.9 MMBtu

● Re-gasification CAPEX:Base Case CAPEX is based on a $575 million for an 850MMCF/day facility.

MMBtu/76.1$350*850000*1.1

)10*575( 6

=

Where one (1) Standard Cubic Foot (CF) = 1100 Btu

The break-even price of gas is the minimum price at which the gas must be sold to makethe LNG project profitable. It is equal to the summation of the raw gas price, OPEX andamortized CAPEX. The markup rate of gas = value added to the raw gas as it goesthrough the value chains – liquefaction, shipping and re-gasification. It is equal to thedifference between the selling price of gas and raw gas price.

Table 3 presents the detailed NCF analysis for the Base Case at a discount rate of15% and a raw gas price of 3.00$/MMBtu, showing a break-even price of $6.57/MMBtu(i.e. a markup of $3.57/MMBtu) and a POT of 5.18 years after start-up.

Table 4 summarizes the pay-out-time (POT) as only a function of the discount ratessince it (POT) is independent of the raw gas price. Thus, at discount rates of 10, 15, 20

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and 25%, the undiscounted POT are 7.82, 5.18, 3.68 and 2.76 years respectively after thestartup of the plant.

Table 5 presents a summary of the sensitivity runs on the break-even (minimum) prices at various CAPEX/OPEX, discount rates, and raw gas prices. The break-even prices range between 3.00$/MMBtu (at Base Case CAPEX less 20%, 10% discount rate

and 1.00$/MMBtu raw gas price) and 12.15$/MMBtu (at Base Case CAPEX plus 20%,25% discount rate and 5.00$/MMBtu raw gas price), yielding an over-all average of7.17$/MMBtu. The corresponding mark-ups range between 2.00 and 7.15$/MMBtu,respectively.

Figure 3 presents the break-even and mark-up prices as a function of raw gas pricesat Base Case CAPEX and 15% discount rate. It is very evident that both (break-even andmark-up prices) increase linearly with increasing raw gas prices yielding slopes of 1.17and 0.17, respectively. These relationships hold true with all 100 cases considered in thesensitivity analysis.

(Basis: Base Case CAPEX and 15% Discount Rate)

0

1

2

3

4

5

6

7

8

9

10

0 1 2 3 4 5 6

Raw Gas Price ($/MMBtu)

Break-even Price($/MMBtu)

0

1

2

3

4

5

Mark-up Price($/MMBtu)

Markup Price

Break Even Price

Figure 3 – A Trend of Break-even and Mark-up Price with Respect to the Raw

Gas Price.

Table 6 – 10 depicts the OPEX values as a percentage of the CAPEX for eachactivity of the LNG value chain for five (5) cases including the Base Case CAPEX, plus10%, plus 20%, minus 10% and minus 20%, respectively. The over-all OPEX range forthe Base Case CAPEX is between 5.47% (using 10% discount rate and 1.00$/MMBtu

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raw gas price) and 12.03$/MMBtu (using 25% discount rate and 5.00$/MMBtu raw gas price), yielding an average of 8.75%. The overall OPEX values for all cases consideredrange between 4.69% (using the Base Case CAPEX plus 20%, 10% discount rate and1.00$/MMBtu raw gas price) and 14.65% of CAPEX (using Base Case CAPEX minus20%, 25% discount rate and 5.00$/MMBtu raw gas price), yielding an over-all average of

8.93%.

Conclusions

The economic viability of a liquefied natural gas project is determined by theCAPEX, OPEX, discount rate, and raw gas price. The mark-up rate (to cover both OPEX& CAPEX) ranges from 2.00 to 7.15$/MMBtu for the range of economic parameters being evaluated. The mark-up price increases linearly with increasing raw gas pricesyielding a slope of 0.17. This relationship holds true with all 100 cases considered in thesensitivity analysis.The corresponding undiscounted POT ranges between 2.76 and 7.82 years aftercommissioning and start-up.

Besides, in view of the various scenarios being considered for the viability of LNG projects, it is evident that low gas prices will favor LNG projects with respect to the break-even and markup prices. On the other hand, stranded natural gas especially

associated gas in regions with zero flare policy such as Nigeria, will make an ideal sourcefor LNG Liquefaction plants. With current crude prices hovering around $100/bbl (firstquarter 2008), LNG projects will provide a viable option in natural gas monetization.

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References

1. Al-Saadoon, F. T., “Economics of GTL Plants”, SPE Hydrocarbon Economics

and Evaluation Symposium, Dallas, April 3-5, 2005.

2. Avellanet, R. A., Thomas, C.P. and Robertson, E.P. “Options for Alaska North

Slope Natural Gas Utilization”, SPE, Western Regional Meeting, Alaska, May

22nd – 24th

, 1996.

3. Barclay, M. and Denton, N., “Selecting Offshore LNG Processes”, LNG Journal,

October, 2005, pg. 34 – 35.

4. Flower, A., “LNG Today”, The Energy Publishing Network Gas Strategies, 2004

Edition.

5. Heren LNG Markets, March 23, 2007.

6. Jensen, T. T., “U.S. Reliance on International Liquefied Natural Gas Supply”, A

Policy Paper prepared for the National Commission on Energy Policy, February,

2004.

7. Kellas, G., “Comparison of LNG Contractual Framework and Fiscal Systems”,

SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, April 5-8,

2003.

8. Mokhatab, S. and Economides, M. J., Onshore LNG Production Process

Selection, SPE, ATC&E, San Antonio, Texas, 2006.

9. Patel, B., “Gas Monetization: A techno-Economic Comparison of GTL and LNG”

7th World Congress of Chemical Engineering, 2005

10. Rowe, D. “LNG Market Overview”, the Oxford Princeton Programme, March 14,

2004.

11. Shukri, T., “LNG Technology Selection”, Hydrocarbon Engineering February,

2004.

12. Subero, G., Sun, K., Deshpande, A., Mclaughlin, J. Economides, M. J., “A

Comparative Study of Sea-going Natural Gas Transport”, SPE Annual Technical

Conference and Exhibition, Houston, Texas, September 26-29, 2004.

13. Yost, C and Dinapoli, R., “Benchmarking Study Compares LNG Plant Costs”.

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Table1 - LNG Trains by Liquefaction Processes (M. Backlay and N. Denton, 2005)

Note: % of Market based on percentage of total trains running and under construction (As of Nov. 2004)

Licensor Liquefaction

Process

Number of Trains

Running Under Planned

Construction

Startup

Year

% of

Market

APCI Propane Pre-cooled MR (PPMR) 55 9 - 1972 77%

Conoco-Phillips Optimized Cascade 3 4 - 1999 9%

APCI Single Refrigerant MR 4 - - 1970s 5%

Marathon/Phillips Classic Cascade 1 - - 1969 1%

Teal Dual Pressure MR 1 - - 1%

Black & Veach Prico Single Stage MR 2 - - 2%

Shell MR Processes (C3MR & Dual-MR) - 3 - 2005 4%

Linde-Statoil Mixed-fluid Cascade - 1 - 2006 1%

APCI AP-X Process - - 4 2007/2008 0%

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Table 2 – LNG Liquefaction Technology Selection Parameters (Shukri 2004)

Technology selection items Pros Cons

Spiral wound exchanger Flexible Operation Proprietary/more expensive

PFHE (Plate Fin HeatExchanger)

Competitive vendorsavailable, Lower pressure,drop and temperaturedifferences

Require careful design toensure good 2-phase flowdistribution in multipleexchanger configurations

Axial compressors High efficiency Suitable only at high flow rates

Large gas turbine Proven, efficient and costeffective

Less reliable/ strictmaintenance cycle/ morecomplicated control/ fixedspeed

Large motor drivers Efficient, flexible & moreavailable

Untried in LNG at speedsneeded/require large power

plants

Mixed refrigerant process Simpler compression system.Adjusting composition allows

process matching

More complex operation.

Pure component Cascade process

Potential higher availabilitywith parallel compression

More equipment andcomplicated compressionsystem

Air cooling (compared to seawater cooling)

Lower cooling system CAPEX Less efficient process/ higheroperating costs

Fluid medium heating(compared to steam)

Eliminates the need for steamgeneration & water treatment

Higher reboiler costs

Larger train capacity Lower specific costs (CAPEX per tonne LNG)

Some equipment/ processesmay require furtherdevelopment

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Table 4 - Pay-out-time (POT) as a Function of Discount Rate

Table 5 – Break-even Prices as a Function of Discount Rates, Raw Gas Costs, CAPEX and OPEX

Discount Rate, % POT, years after start-up

10 7.82

15 5.18

20 3.68

25 2.76

(BREAK-EVEN (MINIMUM) GAS PRICES

CAPEX, U.S. $/MMBtu

%

Less 20% of Base Case CAPEX Less 10% of Base Case CAPEX Base Case Plus 10 % of Base Case CAPDisc.

1 2 3 4 5 1 2 3 4 5 1 2 3 4 5 1 2 3 4

10% 3.00 4.17 5.35 6.52 7.70 3.17 4.34 5.52 6.69 7.87 3.34 4.52 5.69 6.86 8.04 3.51 4.69 5.86 7.04

15% 3.70 4.87 6.05 7.22 8.40 3.96 5.13 6.31 7.48 8.66 4.22 5.39 6.57 7.74 8.91 4.48 5.65 6.82 8.00

20% 4.54 5.71 6.89 8.06 9.23 4.90 6.08 7.25 8.42 9.60 5.26 6.44 7.61 8.79 9.96 5.63 6.80 7.98 9.15

25% 5.51 6.68 7.86 9.03 10.21 5.99 7.17 8.34 9.52 10.69 6.48 7.65 8.83 10.00 11.18 6.96 8.14 9.31 10.49

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Table 6 – OPEX as % of Base Case CAPEX at Various Discount Rates and Raw Gas Costs

DiscountRate %

US $/MM Btu

OPEX AS % of CAPEX

U.S.$/MMBtu

Raw GasCost

CA PEX OPEX

L i q u e f a c t i o n

S h i p p i n g

R e - g a s i f i c a t i o n

T o t a l


S h i p p i n g


T o t a l


S h i p p i n g


O v e r a l l

Break-evenPrice

10.00

1.00

6.40 4.64 1.76 12.80 0.29 0.29 0.12 0.70 4.53 6.25 6.82 5.47 3.34

15.00 6.40 4.64 1.76 12.80 0.29 0.31 0.14 0.74 4.53 6.68 7.95 5.78 4.22

20.00 6.40 4.64 1.76 12.80 0.29 0.34 0.16 0.79 4.53 7.33 9.09 6.17 5.26

25.00 6.40 4.64 1.76 12.80 0.29 0.37 0.19 0.85 4.53 7.97 10.80 6.64 6.48

10.00

2.00

6.40 4.64 1.76 12.80 0.38 0.35 0.15 0.88 5.94 7.54 8.52 6.88 4.52

15.00 6.40 4.64 1.76 12.80 0.38 0.37 0.17 0.92 5.94 7.97 9.66 7.19 5.39

20.00 6.40 4.64 1.76 12.80 0.38 0.39 0.19 0.96 5.94 8.41 10.80 7.50 6.44

25.00 6.40 4.64 1.76 12.80 0.38 0.42 0.22 1.02 5.94 9.05 12.50 7.97 7.65

10.00

3.00

6.40 4.64 1.76 12.80 0.47 0.40 0.18 1.05 7.34 8.62 10.23 8.20 5.69

15.00 6.40 4.64 1.76 12.80 0.47 0.42 0.20 1.09 7.34 9.05 11.36 8.52 6.57

20.00 6.40 4.64 1.76 12.80 0.47 0.45 0.22 1.14 7.34 9.70 12.50 8.91 7.61

25.00 6.40 4.64 1.76 12.80 0.47 0.48 0.25 1.20 7.34 10.34 14.20 9.38 8.83

10.00

4.00

6.40 4.64 1.76 12.80 0.56 0.46 0.21 1.23 8.75 9.91 11.93 9.61 6.86

15.00 6.40 4.64 1.76 12.80 0.56 0.48 0.23 1.27 8.75 10.34 13.07 9.92 7.74

20.00 6.40 4.64 1.76 12.80 0.56 0.51 0.25 1.32 8.75 10.99 14.20 10.31 8.79

25.00 6.40 4.64 1.76 12.80 0.56 0.53 0.28 1.37 8.75 11.42 15.91 10.70 10.00

10.00

5.00

6.40 4.64 1.76 12.80 0.65 0.51 0.24 1.40 10.16 10.99 13.64 10.94 8.04

15.00 6.40 4.64 1.76 12.80 0.65 0.54 0.26 1.45 10.16 11.64 14.77 11.33 8.91

20.00 6.40 4.64 1.76 12.80 0.65 0.56 0.28 1.49 10.16 12.07 15.91 11.64 9.96

25.00 6.40 4.64 1.76 12.80 0.65 0.59 0.30 1.54 10.16 12.72 17.05 12.03 11.18

7/21/2019 SPE-120745-MS


Table 7 – OPEX as % of Base Case CAPEX (plus 10%) at Various Discount Rates and Raw Gas Costs

DiscountRate %

US $/MM Btu

OPEX AS % of CAPEX

U.S.$/MMBtu

Raw GasCost

CA PEX OPEX


S h i p p i n g


T o t a l


S h i p p i n g


T o t a l


S h i p p i n g


O v e r a l l

Break-evenPrice

10.00

1.00

7.04 5.12 1.92 14.08 0.29 0.30 0.13 0.72 4.12 5.86 6.77 5.11 3.51

15.00 7.04 5.12 1.92 14.08 0.29 0.32 0.15 0.76 4.12 6.25 7.81 5.40 4.48

20.00 7.04 5.12 1.92 14.08 0.29 0.35 0.17 0.81 4.12 6.84 8.85 5.75 5.63

25.00 7.04 5.12 1.92 14.08 0.29 0.38 0.20 0.87 4.12 7.42 10.42 6.18 6.96

10.00

2.00

7.04 5.12 1.92 14.08 0.38 0.35 0.16 0.89 5.40 6.84 8.33 6.32 4.69

15.00 7.04 5.12 1.92 14.08 0.38 0.37 0.18 0.93 5.40 7.23 9.38 6.61 5.65

20.00 7.04 5.12 1.92 14.08 0.38 0.40 0.20 0.98 5.40 7.81 10.42 6.96 6.80

25.00 7.04 5.12 1.92 14.08 0.38 0.44 0.23 1.05 5.40 8.59 11.98 7.46 8.14

10.00

3.00

7.04 5.12 1.92 14.08 0.47 0.41 0.18 1.06 6.68 8.01 9.38 7.53 5.86

15.00 7.04 5.12 1.92 14.08 0.47 0.43 0.21 1.11 6.68 8.40 10.94 7.88 6.82

20.00 7.04 5.12 1.92 14.08 0.47 0.46 0.23 1.16 6.68 8.98 11.98 8.24 7.98

25.00 7.04 5.12 1.92 14.08 0.47 0.49 0.26 1.22 6.68 9.57 13.54 8.66 9.31

10.00

4.00

7.04 5.12 1.92 14.08 0.56 0.46 0.21 1.23 7.95 8.98 10.94 8.74 7.04

15.00 7.04 5.12 1.92 14.08 0.56 0.49 0.23 1.28 7.95 9.57 11.98 9.09 8.00

20.00 7.04 5.12 1.92 14.08 0.56 0.51 0.26 1.33 7.95 9.96 13.54 9.45 9.15

25.00 7.04 5.12 1.92 14.08 0.56 0.55 0.29 1.40 7.95 10.74 15.10 9.94 10.49

10.00

5.00

7.04 5.12 1.92 14.08 0.65 0.52 0.24 1.41 9.23 10.16 12.50 10.01 8.21

15.00 7.04 5.12 1.92 14.08 0.65 0.54 0.26 1.45 9.23 10.55 13.54 10.30 9.17

20.00 7.04 5.12 1.92 14.08 0.65 0.57 0.29 1.51 9.23 11.13 15.10 10.72 10.33

25.00 7.04 5.12 1.92 14.08 0.65 0.60 0.32 1.57 9.23 11.72 16.67 11.15 11.66

7/21/2019 SPE-120745-MS


Table 8 – OPEX as % of Base Case CAPEX (plus 20%) at Various Discount Rates and Raw Gas Costs

DiscountRate %

US $/MM Btu

OPEX AS % of CAPEX

U.S.$/MMBtu

Raw GasCost

CA PEX OPEX


S h i p p i n g


T o t a l


S h i p p i n g


T o t a l


S h i p p i n g


O v e r a l l

Break-evenPrice

10.00

1.00

7.68 5.56 2.12 15.36 0.29 0.30 0.13 0.72 3.78 5.40 6.13 4.69 3.68

15.00 7.68 5.56 2.12 15.36 0.29 0.33 0.15 0.77 3.78 5.94 7.08 5.01 4.73

20.00 7.68 5.56 2.12 15.36 0.29 0.36 0.18 0.83 3.78 6.47 8.49 5.40 5.99

25.00 7.68 5.56 2.12 15.36 0.29 0.39 0.21 0.89 3.78 7.01 9.91 5.79 7.45

10.00

2.00

7.68 5.56 2.12 15.36 0.38 0.36 0.16 0.90 4.95 6.47 7.55 5.86 4.86

15.00 7.68 5.56 2.12 15.36 0.38 0.38 0.18 0.94 4.95 6.83 8.49 6.12 5.91

20.00 7.68 5.56 2.12 15.36 0.38 0.41 0.21 1.00 4.95 7.37 9.91 6.51 7.1725.00 7.68 5.56 2.12 15.36 0.38 0.45 0.24 1.07 4.95 8.09 11.32 6.97 8.62

10.00

3.00

7.68 5.56 2.12 15.36 0.47 0.41 0.19 1.07 6.12 7.37 8.96 6.97 6.03

15.00 7.68 5.56 2.12 15.36 0.47 0.44 0.21 1.12 6.12 7.91 9.91 7.29 7.08

20.00 7.68 5.56 2.12 15.36 0.47 0.47 0.24 1.18 6.12 8.45 11.32 7.68 8.34

25.00 7.68 5.56 2.12 15.36 0.47 0.50 0.27 1.24 6.12 8.99 12.74 8.07 9.80

10.00

4.00

7.68 5.56 2.12 15.36 0.56 0.47 0.22 1.25 7.29 8.45 10.38 8.14 7.21

15.00 7.68 5.56 2.12 15.36 0.56 0.49 0.24 1.29 7.29 8.81 11.32 8.40 8.26

20.00 7.68 5.56 2.12 15.36 0.56 0.52 0.27 1.35 7.29 9.35 12.74 8.79 9.51

25.00 7.68 5.56 2.12 15.36 0.56 0.56 0.30 1.42 7.29 10.07 14.15 9.24 10.97

10.00

5.00

7.68 5.56 2.12 15.36 0.65 0.52 0.25 1.42 8.46 9.35 11.79 9.24 8.38

15.00 7.68 5.56 2.12 15.36 0.65 0.55 0.27 1.47 8.46 9.89 12.74 9.57 9.4320.00 7.68 5.56 2.12 15.36 0.65 0.58 0.29 1.52 8.46 10.43 13.68 9.90 10.69

25.00 7.68 5.56 2.12 15.36 0.65 0.61 0.33 1.59 8.46 10.97 15.57 10.35 12.15

7/21/2019 SPE-120745-MS


Table 9 – OPEX as % of Base Case CAPEX (minus 10%) at Various Discount Rates and Raw Gas Costs

DiscountRate %

US $/MM Btu

OPEX AS % of CAPEX

U.S.

$/MMBtu

Raw GasCost

CA PEX OPEX


S h i p p i n g


T o t a l


S h i p p i n g


T o t a l


S h i p p i n g


O v e r a l l

Break-evenPrice

10.00

1.00

5.76 4.16 1.60 11.52 0.29 0.29 0.12 0.70 5.03 6.97 7.50 6.08 3.17

15.00 5.76 4.16 1.60 11.52 0.29 0.31 0.14 0.74 5.03 7.45 8.75 6.42 3.96

20.00 5.76 4.16 1.60 11.52 0.29 0.33 0.16 0.78 5.03 7.93 10.00 6.77 4.90

25.00 5.76 4.16 1.60 11.52 0.29 0.36 0.18 0.83 5.03 8.65 11.25 7.20 5.99

10.00

2.00

5.76 4.16 1.60 11.52 0.38 0.34 0.15 0.87 6.60 8.17 9.38 7.55 4.34

15.00 5.76 4.16 1.60 11.52 0.38 0.36 0.17 0.91 6.60 8.65 10.63 7.90 5.13

20.00 5.76 4.16 1.60 11.52 0.38 0.39 0.19 0.96 6.60 9.38 11.88 8.33 6.08

25.00 5.76 4.16 1.60 11.52 0.38 0.41 0.21 1.00 6.60 9.86 13.13 8.68 7.17

10.00

3.00

5.76 4.16 1.60 11.52 0.47 0.40 0.18 1.05 8.16 9.62 11.25 9.11 5.52

15.00 5.76 4.16 1.60 11.52 0.47 0.42 0.19 1.08 8.16 10.10 11.88 9.38 6.31

20.00 5.76 4.16 1.60 11.52 0.47 0.44 0.21 1.12 8.16 10.58 13.13 9.72 7.25

25.00 5.76 4.16 1.60 11.52 0.47 0.47 0.24 1.18 8.16 11.30 15.00 10.24 8.34

10.00

4.00

5.76 4.16 1.60 11.52 0.56 0.45 0.21 1.22 9.72 10.82 13.13 10.59 6.69

15.00 5.76 4.16 1.60 11.52 0.56 0.47 0.22 1.25 9.72 11.30 13.75 10.85 7.48

20.00 5.76 4.16 1.60 11.52 0.56 0.50 0.24 1.30 9.72 12.02 15.00 11.28 8.42

25.00 5.76 4.16 1.60 11.52 0.56 0.52 0.27 1.35 9.72 12.50 16.88 11.72 9.5210.00

5.00

5.76 4.16 1.60 11.52 0.65 0.51 0.24 1.40 11.28 12.26 15.00 12.15 7.87

15.00 5.76 4.16 1.60 11.52 0.65 0.53 0.25 1.43 11.28 12.74 15.63 12.41 8.66

20.00 5.76 4.16 1.60 11.52 0.65 0.55 0.27 1.47 11.28 13.22 16.88 12.76 9.60

25.00 5.76 4.16 1.60 11.52 0.65 0.58 0.29 1.52 11.28 13.94 18.13 13.19 10.69

7/21/2019 SPE-120745-MS


Table 10 – OPEX as % of Base Case CAPEX (minus 20%) at Various Discount Rates and Raw Gas Costs

DiscountRate %

US $/MM Btu

OPEX AS % of CAPEX

U.S.$/MM

Btu

RawGasCost

CA PEX OPEX


S h i p p i n g


T o t a l


S h i p p i n g


T o t a l


S h i p p i n g


O v e r a l l

Break-evenPrice

10.00

1.00

5.12 3.72 1.40 10.24 0.29 0.28 0.12 0.69 5.47 7.53 8.57 6.74 3.00

15.00 5.12 3.72 1.40 10.24 0.29 0.30 0.13 0.72 5.86 8.06 9.29 7.03 3.70

20.00 5.12 3.72 1.40 10.24 0.29 0.32 0.15 0.76 6.25 8.60 10.71 7.42 4.54

25.00 5.12 3.72 1.40 10.24 0.29 0.34 0.17 0.80 6.64 9.14 12.14 7.81 5.51

10.00

2.00

5.12 3.72 1.40 10.24 0.38 0.34 0.15 0.87 6.64 9.14 10.71 8.50 4.17

15.00 5.12 3.72 1.40 10.24 0.38 0.36 0.16 0.90 7.03 9.68 11.43 8.79 4.87

20.00 5.12 3.72 1.40 10.24 0.38 0.38 0.18 0.94 7.42 10.22 12.86 9.18 5.71

25.00 5.12 3.72 1.40 10.24 0.38 0.40 0.20 0.98 7.81 10.75 14.29 9.57 6.68

10.00

3.00

5.12 3.72 1.40 10.24 0.47 0.39 0.17 1.03 7.62 10.48 12.14 10.06 5.35

15.00 5.12 3.72 1.40 10.24 0.47 0.41 0.19 1.07 8.01 11.02 13.57 10.45 6.05

20.00 5.12 3.72 1.40 10.24 0.47 0.43 0.21 1.11 8.40 11.56 15.00 10.84 6.89

25.00 5.12 3.72 1.40 10.24 0.47 0.46 0.23 1.16 8.98 12.37 16.43 11.33 7.86

10.00

4.00

5.12 3.72 1.40 10.24 0.56 0.45 0.20 1.21 8.79 12.10 14.29 11.82 6.52

15.00 5.12 3.72 1.40 10.24 0.56 0.47 0.22 1.25 9.18 12.63 15.71 12.21 7.22

20.00 5.12 3.72 1.40 10.24 0.56 0.49 0.24 1.29 9.57 13.17 17.14 12.60 8.06

25.00 5.12 3.72 1.40 10.24 0.56 0.51 0.26 1.33 9.96 13.71 18.57 12.99 9.03

10.00

5.00

5.12 3.72 1.40 10.24 0.65 0.51 0.23 1.39 9.96 13.71 16.43 13.57 7.70

15.00 5.12 3.72 1.40 10.24 0.65 0.52 0.25 1.42 10.16 13.98 17.86 13.87 8.40

20.00 5.12 3.72 1.40 10.24 0.65 0.54 0.26 1.45 10.55 14.52 18.57 14.16 9.23

25.00 5.12 3.72 1.40 10.24 0.65 0.57 0.28 1.50 11.13 15.32 20.00 14.65 10.21

spe-120745-ms

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