flng economics and market potential -...

FLNG Economics and Market Potential

Philip Fjeld

CEO, FLEX LNG Management Ltd

Singapore, 10 February 2011

Private and Confidential

Brief Introduction to FLEX LNG

FLNG Market and Size Considerations

FLNG Economics vs Onshore

Summary

FLEX LNG– a brief introduction

� FLEX LNG Ltd was founded in 2006 to commercialize floating LNG liquefaction vessels

� Currently four LNG Producer hulls on order at Samsung Heavy Industries in Korea

� All units targeted with a liquefaction capacity of up to 2.0 mtpa

� Lumpsum, turnkey EPCIC contract for LNGP no.1

� Offices in London, Oslo, Singapore, Australia and Korea with broad competence and experienceexperience

� Great support from SHI and numerous contractors and suppliers

� Strong support from our shareholders, with ”K”-Line as the largest shareholder

� An advanced generic FLNG design has been developed with great adaptability for many different field-specific requirements

3

FLEX LNG Producer– Key facts

Liquefaction Capacity:1.7-2.0 mtpa LNG

Overall (riser to offloading) Fuel Shrinkage: Approx. 10 %

ClassificationDNV

Maintenance20 years on-station maintenance

TurretInternal Submerged Turret Production system (STP) from APL

Accomodation120/150 POB (regular + temporary)

LNG Storage Capacity : 170 – 185 000 m3

Condensate/LPG Storage: 25 – 50 000 m3

Image courtesy to Samsung Heavy Industries

Feed Gas: Approx. 250 – 300 mmscf/day

4

FLEX LNG Producer- Generic concept taking adaptability and broad envelope of fields into account

Generic topsides Field-specific topsides

Liquefaction and fine removal of acid gas, water and mercury

Field specific treatment to condition the gas for generic part

Condensate and LPG handling

module

MEG Reclamation and injection

module

5

� Field Specific Pre-FEED/FEED Designs Concluded in Parallel with the Generic Development

� Medium rich feed gas with high CGR

Project 1 Project 2 Project 3

� LPG rich feed gas and requirement for MEG

� Very lean feed gas with long tail of HHCs and MEG

Project 4 Project 5

� Nitrogen rich feed gas

(~10 mol%)

� CO2 rich feed gas

(~20 mol%)

The AP-XTM sub-cooling cycle uses N2 expansion

Nitrogen Expansion – Proven in Applications and Size- Successfull application of large nitrogen expansion system paves the way for FLNG

� Nitrogen liquefiers, air separation

� Peak shaving plants

� Re-liquefaction onboard LNG carriers

� Sub-cooling of mega trains (AP-XTM)

� Proven technology for a range of applications

� Proven technology in size

2

� Largest N2 expansion system in use

� Selected for trains QG 4,5,6,7 and RG 6,7

� The N2 cycle compressor is directly driven by a GE frame 9 gas turbine (100MW rated at 49 deg C)

� The system uses 4 cold expanders and 1 warm expander

� A BAHX is used as nitrogen cold box

Courtesy: APCI

6

The N2 part of the AP-XTM system is equivalent to a 1.5-2 mtpa stand-alone system

. . . . . . twice the size of an LNG Producer liquefaction train!

LNG Containment Technology– SPB tank technology the only safe and reliable option for FLNG

� Excellent track record for LNG since 1993

� Applied successfully for gas FPSO/FSOs

� Maximized flat deck space for topside

� Self supporting tanks allows for in-situ

SPB Containment

Membrane

� Filling restrictions

Spherical

�No filling restrictions

�On-site inspection

& Maintenance

� Limited deck-space

� SPB Tank Technology Superior for LNG Production

inspection and maint. without dry-docking

� Only containment system with all features

required for safe and reliable offshore LNG

7

� Filling restrictions

� On-site inspection

& Maintenance

� Flat deck-space

2-Row Membrane� Filling restrictions� On-site inspection

& Maintenance� Flat deck-space

SPB� No filling restrictions� On-site inspection

& Maintenance� Flat deck-space

Sloshing Free Tank System

Inspection and Maintenance Access

EPCIC Contract with Samsung Heavy Industries- Unique guarantees provided by SHI enabling strong commercial structure

� Single EPCIC contract,

� Lumpsum, turnkey delivery of the LNG Producer

� Includes all works from FEED through detailed engineering, procurement, construction and integration, to commissioning (at-shore and offshore)

� Minimised integration risk

� Includes full-scale liquefaction test prior to sail-away

� Clear legal responsibilities

� Extensive performance guarantees and LDs� Extensive performance guarantees and LDs

� Production capacity

� Fuel efficiency

� Plant reliability

� Defect rectification liabilities

8

� Close collaboration together with financial and legal advisors in order to ensure commercial structures that together with the EPCIC framework will result in alignment and bankable projects

� Samsung guarantees performance up to the level required by the project finance debt providers


FLEX LNG and the LNG Producer Concept



Summary

Multiple Applications for LNG FPSOs

Small stranded offshore non-associated gas fields

� Provide a economical development concept for stranded offshore gas fields

Onshore gas fields

� Offer a cheaper, quicker, and less complex solution for onshore gas fields (e.g. Papua New Guinea, CSG projects in Australia)

Associated gas projects

� Provide a viable alternative for large scale associated gas flaring or reinjection projects (e.g. in West Africa, Gulf of Mexico)

Pipeline gas

10

Early production/cash flow

� Provide an early production system for large offshore gas fields

� Lead time to first cash flow can typically be cut by 50%

Large gas field – staged developments

� Accelerate production and provide lower production cost per ton for large developed gas fields that have liquefaction capacity constraints

Deepwater gas fields/long tie-back distances

� Reduce CAPEX for deepwater offshore gas fields and long tieback distances

� Locate LNG FPSO alongside a jetty. Liquefy gas taken from existing pipeline infrastructure (e.g. the domestic pipeline grid)

Floating LNG is a Smarter Way to Produce LNG- But can economy of scale lower the costs further?

1 x Large FLNG barge Multiple Medium Sized LNG Producers

11

Economy of Scale for LNG FPSO– “Bigger” is not always better

Multiple Units Attractive for Reserve Owner and Regulator – Enhanced Field Development

300

400

500

600

Production (mmscf/d)

LNGP2

LNGP potential redeployment or tie in more gas

12

0

100

200

300

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038

Production (mmscf/d)

Gas Reserve Production Profile Large FLNG Production Capacity LNGP Production Capacity

LNGP1

Maximise Existing Ship Yard Facilities and Knowledge– “Bigger” is not always better

Large FLNG barge concepts do not fit within existing construction practices,

� Overall topsides weight

� Module size and weight

� Lifting and handling

� Yard slot

� Time in dock

Stretching Yard LimitsVessel Size Comparison

60

80

100

120

Vessel beam (m)

Existing FPSOs

LNG Producer

Large FLNG barges

� Time in dock

� Equipment sizes

� Complexity

� Larger risks:

� Construction

� Integration

� Completion

� Performance

� Cost & schedule

A Mid-Sized LNG FPSO Represents ~2 Equivalent Yard Slots Compared to 8-10 for a Large FLNG Barge

0

20

40

0 100 200 300 400 500 600

Vessel beam (m)

Vessel length (m)

13

70

80

90

100

110

Topside W

eight ('000 tons)

Medium-scale FLNG Topsides Within Proven Range

Comparison of Topside Weights

Unproven Range

?

0

10

20

30

40

50

60

Bonga Kizomba A/B

N'Kossa Dalia LNGP Girassol Belanak Pazflor Large FLNG

Concept

Topside W

eight ('000 tons)

14

Proven Range

Potential Economies of Scale for LNG FPSO– “Bigger” is not always better

Case Study

1 x LNGP 2 x LNGP Large FLNG

Production (mtpa) 1.7 3.4 3.5

CAPEX EPCIC (mill USD) 1300 2600 5000

Shrinkage (%) 10.5 10.5 8

OPEX (USD p.d.) 110,000 220,000 220,000

Start 2014 2014 2014

� Two fields are evaluated of 2.0 and 5.0 TCF

15

� Two fields are evaluated of 2.0 and 5.0 TCF

� CAPEX service costs are calculated as a tolling structure where the NPV of the tolling fees equals

the NPV of the CAPEX costs

� The time to pay down the CAPEX is taken equal as the field life (i.e. no residual value)

� Discount factor is 11%

� Analysis is based on lean feedgas, although both can produce LPG and condensate for rich feedgas.

� A basic OPEX figure is used, which will vary per project and it will most likely not be double for a

dual vessel or a large barge solution.

Potential Economies of Scale for LNG FPSO– “Bigger” is not always better

Liquefaction Costs

2

3

4

5

6

7

8

Liq

ue

fact

ion

co

sts

($/m

mb

tu)

OPEX

Efficiency sales loss (15 $/mmbtu)

CAPEX service

2.0

3.0

4.0

5.0

6.0

7.0

NP

V(1

1%

) o

f p

roje

ct c

ash

flo

w (

bil

lio

n U

SD

)

LNG 7 $/mmbtu

LNG 12 $/mmbtu

NPV Project Cash Flow

16

21 yrs 10.5 yrs 26 yrs

0

1

2

1 x LNGP 2 x LNGP FLNG barge 2 x LNGP FLNG barge

2 TCF 5 TCF

Liq

ue

fact

ion

co

sts

($/m

mb

tu)

-2.0

-1.0

0.0

1.0

2.0

1 x LNGP 2 x LNGP FLNG barge 2 x LNGP FLNG barge

2 TCF 5 TCFNP

V(1

1%

) o

f p

roje

ct c

ash

flo

w (

bil

lio

n U

SD

)

21 yrs 10.5 yrs 26 yrs

At 12 $/mmbtu the CAPEX of the Large FLNG should reduce to ~3000 million USD to

equal NPV at 26 yrs production

Note: A lower efficiency implies the use of more feedgas, which cannot be sold as LNG. The efficiency difference is thus included as a cost charged with the LNG market price . Tolling fee is calculated to obtain equal NPV of the capital expenditures and the tolling revenues. Cashflow calculation includes a 2 $/mmbtu feedgas cost.





Summary

“....liquefaction development costs are “....liquefaction development costs are unsustainably high. They will come down to 350 USD/ton in the future....”

Onshore LNG Development Costs Remain Stubbornly High

� The recent global economic turmoil has resulted in some cost reductions in the oil and gas industry

� The IHS CERA Upstream Capital Costs Index (UCCI) tracks costs associated with the construction of new oil and gas facilities

� Values are indexed to the year 2000,

New Paradigm For The LNG Industry

210

230

210

202

201 207

100

120

140

160

180

200

220

240

UCCI Index

� Values are indexed to the year 2000, meaning that capital costs of $1 billion in 2000 would in May 2010 equal $2.02 billion

� However, although the UCCI has dropped from the peak in November 2008, Q1 figures for 2010 have indicated a clear increase in the index and it seems unlikely that development costs will near term come back down to figures seen 6-10 years ago

19

Source: IHS Cambridge Energy Research Associates (IHS CERA)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 2 4 6 8 10 12 14 16

USD/ton liquefaction capacity

Annual LNG liquefaction capacity (mtpa)

Source: FLEX LNG, Industry Reports

FLEX LNG(2014)

ALNG(Trinidad 2003)

Gorgon LNG(late 2014)

Pluto LNG(2011)

Angola(late 2012)

PNG LNG(2014)

QCLNG(2014)

GLNG(2014)

100

Nov 2005

May 2006

Nov 2006

May 2007

Nov 2007

May 2008

Nov 2008

May 2009

Nov 2009

May 2010

Nov 2010

The Future of Australian LNG is Maybe Not so Bright- Australian LNG projects are high cost and future projects could be threatened

Unconventional Gas in the US and future LNG export capacity from the US

Narrowing of Global LNG Price Spread

Lower Cost LNG Alternatives –i.e. FLNG

Threats to Future Australian LNG Projects� Australian LNG projects sanctioned

recently are the world’s most costly projects (by a wide margin) and are enjoying a “perfect storm”

� Moratorium for future LNG projects in Qatar

� Depressed gas prices in Atlantic Basin

� Record economic growth in Asia

� Robust oil prices

� Continued wide global gas market

20

Future Australian LNG

Projects

Price Spread

Development of Labour and EPC

Market in Australia

Competition from Clean Coal and Increase in

Nuclear

Unconventional Gas in Asia

i.e. FLNG� Continued wide global gas market price spread

� Lack of competing LNG projects and continued strong oil price link is providing the foundation needed to execute on LNG projects in Australia that would be uneconomic elsewhere

� What will the future look like if oil prices drop, the link to oil weakens substantially or more competitive LNG development options are embraced by the industry?

FLNG Bundles Facilities and Infrastructure Into 1 Unit- A significant cost saving opportunity

Offshore facilities12%

Delivery trunkline12%

Marine facilities6%

Onshore site

LNG plant37%

Product Storage5%

21

An Onshore LNG Development Involves Logistical Complexities not Present With FLNG

An FLNG Yard Utilises Existing Infrastructure, Eliminating Dedicated Investments

Data source: Worley Parsons

Onshore site preparations

5%

Site civil works6%

Wells12%

Subsea infrastructure

5%

Economies of Scale Are Not Working- New land-based LNG plants are considerably more expensive than FLNG

Onshore LNG Projects are Significantly More Costly Than “Medium-scale” FLNG

Project Capacity (mtpa) CAPEX (BUSD)Comparable Costs

(71%)

CAPEX USD/ton

liquefaction capacity

Gorgon 15.0 37.0 26.3 1751

PNG LNG 6.6 15.0 10.7 1614

QCLNG 7.4 15.0 10.7 1439

GLNG 7.2 19.0 13.5 1874

FLEX LNG 1.85 1.3 1.3 703

Wheatstone 10.0 16.0 11.4 1136

22

Building in a Controlled Environment Greatly Reduces CAPEX and Complexity

(1) 29% capex reduction for wells, subsea, offshore facilities

Source: Company Reports, UBS and J.P.Morgan estimates

Sunrise 5.0 10.9 7.7 1545

Browse 14.0 24.6 17.5 1250

APLNG 7.0 13.8 9.8 1404

Scarborough 6.0 11.2 8.0 1325

Liquefaction CAPEX Service Costs ($/mmbtu)- Significant reduced liquefaction cost from FLNG

Future Costs of Land-based Liquefaction Requires 4 – 6 $/MMBtu

23

Tolling fee is calculated to obtain equal NPV of the capital expenditures and the tolling revenues.

Assumptions: 25 years of operations, 11% discount factor

The “Asian Utility” Example

� A typical Asian utility would like to lower its cost of LNG supply

� If we assume that being fortunate with timing and only securing long term supply in a “buyers market” is not a sustainable long term strategy, then what options are open to the Asian utility?

� One of the best options would be to offset cost of LNG by taking equity in liquefaction projects (upstream and/or midstream). This leaves two options

Asian Utility Wishing to Take Equity in Liquefaction Project

Traditional LNG Project Developed by Major/IOC/NOC

� Asian utility likely to be allowed to enter

project at FID (or close to FID)

� Small stake offered (~1-5%)

� Significant equity premium paid to enter

project

� LNG sold at market price

Mid-Sized LNG Project Developed by Untraditional LNG Player(s)

� Asian utility likely to be allowed to enter

project at an early stage

� 20-50% stake is achievable

� Significant discount offered for equity

investment compared to investing at FID

� LNG sold at discount to market price





Summary

Summary

� LNG FPSOs offer compelling arguments.....

� Monetisation of commercially challenged gas reserves

� Lead time less than 50% of a traditional liquefaction project

� Unit CAPEX of 550-700 USD/tons liquefaction capacity

� Redeployability

� Strategic and commercial independence

� Increased revenue/taxation for host governments compared to an onshore development

� Considerably reduced environmental impact compared to an onshore � Considerably reduced environmental impact compared to an onshore development

� .....and as the first FLNG units are deployed the industry will see the following changes:

� New LNG supply can be developed in less than two years

� LNG supply projects will appear in locations unimaginable today (i.e. liquefying pipeline gas supplied from existing grid)

� Onshore liquefaction projects will have to innovate and become more cost effective to remain competitive

� Companies with no previous affiliation to the LNG industry can be become substantial LNG suppliers

� Traditional end-users of LNG will integrate upstream and take control over their own LNG supply destiny 26

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