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LNG market outlook Time to get liquid

October 2012

Please refer to important disclosures at the end of this document

Sigurd-Erik Nissen-Meyer Direct: +47 2413 2134 Mobile: +47 9186 6247

Email: [email protected]

Per Kristian Reppe Direct: +47 2413 2187

Mobile: +47 90 03 32 03 Email: [email protected]

2

Summary

LNG demand: Should grow 5-7% on average p.a. through 2025

Gas demand shows solid growth

Gas is cheap, clean, plentiful and has ample upside through substitution

LNG should be increasingly important to bring the gas to the end-user markets

Liquefaction: Capacity is set for growth. LNG prices support FIDs

Regasification: Solid pipeline of regasification projects. In the FSRU market, there is potential for 6-8 contract awards next 12 months, and 30+ by 2015

Shipping: Looks to be the bottleneck in 2012-2013. All set for windfall returns ahead

3

The outlook for gas and LNG demand is strong

Strong growth in LNG demand is underpinned by solid growth in gas, of which an increasing share is met by LNG

Gas is cheap, clean, plentiful and has ample upside through substitution

Source: BP; Wood Mackenzie; Exxon; IEA; EIA; Pareto

World annual demand growth in 2010 – 2030 by energy source

6.0%

1.9%

1.0% 0.9%

2.2%

0%

1%

2%

3%

4%

5%

6%

7%

LNG Gas Coal Oil Nuclear

World demand CAGR 2010 - 2030

4

LNG takes a larger share of the gas market

Key drivers for more LNG:

Cost efficient transport

Diversification for consumers

Flexibility for producers

Cheap source of gas supply

Source: BP; IEA; EIA; Wood Mackenzie; Pareto

World LNG and gas demand 2000 – 2030e

6%

9%

14%

19%

0%

5%

10%

15%

20%

25%

0

1,000

2,000

3,000

4,000

5,000

2000 2010 2020e 2030e

World gas demand World LNG demand LNG share of total

World demand, bcm/year LNG share of total

5

More LNG capacity is needed to bring the gas to the end-users

Source: BP; Company data; EIA; IEA; Pareto

Change in gas imports/exports, and new LNG capacity between major regions 2010 – 2035e

160

5

500

250

230

200

Europe Eurasia

Asia ME

N. Am

Africa

120

Australia

Imports

Exports

New LNG capacity

All figures are in bcm/year

6

Regional price differentials and hence arbitrage opportunities is the catalyst for new capacity

Source: Bloomberg; IEA; Wood Mackenzie; Pareto

Global gas prices/costs

6

USD 17

Gas price/cost (USD/mmbtu)

New LNG capacity

USD 3

USD 9

USD 0-6

USD 0-6

USD 4-6

USD 2-8

Price differentials imply strong economics for LNG projects

10 12 12 13 14 15 17 17 1821 23

26

55

0

5

10

15

20

25

30

'00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '11 +prop.

Number of LNG importing countries

7

The number of LNG importing countries increases rapidly

Source: BP; TRI-ZEN; Teekay; Wood Mackenzie; Höegh LNG; Pareto

Number of LNG importing countries

2000 – 2011: +160%

114

68

51

92

51

17

0

20

40

60

80

100

120

Oil Coal* Nuclear* Gas, Japan Gas, EU Gas, US

USD/boe

8

Gas is relatively cheap

*Takes capex, opex (OECD level) and efficiency of coal, nuclear and gas power plants into account. Assumes carbon cost of USD 20/ton Source: Bloomberg; IEA; Pareto

Energy prices in USD per barrel of oil equivalent, adjusted for energy efficiency

9

Gas is clean and plentiful

CO2 emissions from gas power are half the level of coal power

Gas resources amount to more than 250 years at current production level

*Conventional and unconventional Source: IEA; Pareto

Power plant CO2 emissions Amount of recoverable resources: Oil vs. gas

254

180

0

50

100

150

200

250

300

Gas Oil

Recoverable resources* (Years of 2010 production)

330

715

0

100

200

300

400

500

600

700

800

Gas power plants Coal power plants

CO2 emissions from new power plants (kg/MWh)

0

2,000

4,000

6,000

8,000

10,000

Gas demand 2011 Gas demand 2011 + Powergen. substitution

Gas demand 2011 + Powergen. + Transport substitution

bcm

10

There is ample upside to gas demand through oil, coal and nuclear substitution

*100% substitution from oil, coal and nuclear to gas in power generation and 100% from oil to gas in transportation Source: Exxon; IEA; Pareto

World gas demand 2011 and upside through substitution*

6,400 bcm +98%

8,970 bcm +178%

3,223 bcm

Global LNG demand 2011: 331 bcm

11 Source: BP; Bloomberg; Pareto 11

To sum it up: Gas appears to be a key solution to the energy crisis

Oil Record low spare production capacity. Oil prices set global economic

growth at risk

Coal Dirty and not cheap anymore. Coal prices are 100-300% higher than

2001-2005 average

Nuclear Controversial following the disaster in Japan

Renewables Expensive and weather dependent

Gas Cheap, clean, plentiful. Ample substitution opportunities towards gas

Characteristics and trends

0

100

200

300

400

500

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Oil demand Gas demand

Chinese oil and gas demand (bcm/year)

12

In 2000-2010, China was a game changer for oil

In 2000–2010, Chinese oil demand

climbed from 264 bcm to 500 bcm

accounted for 40% of global growth

exceeded consensus forecast by 50-100%

Chinese gas demand posted solid growth, but nowhere near the levels seen for oil

Source: BP; Pareto

Chinese oil and gas demand 1965 – 2010

0

100

200

300

400

500

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Oil demand Gas demand

Chinese oil and gas demand (bcm/year)

13

In 2011-2020, China can spur a similar growth in gas demand

Chinese gas demand could climb from 109 bcm in 2010 to 400 bcm in 2020

Rapid growth is supported by

government targets to double the share of gas in total energy demand by 2015

import infrastructure; ~170 bcm is under construction or proposed

Source: BP; IEA; Pareto

Chinese oil and gas demand 1965 – 2020e

14

The LNG market should finally get exposure to Chinese growth

China has until recently been non-existent in the LNG market

China’s share of global LNG imports reached 5% in 2011 and should be set for rapid growth going forward, reaching ~12% by 2015

Chinese regas capacity increases >27% p.a. in 2012-2015

Source: EIA; BP; Pareto

China’s share of global LNG imports 2000 – 2015e

0 %

2 %

4 %

6 %

8 %

10 %

12 %

14 %

2000 2002 2004 2006 2008 2010 2012e 2014e

China's share of global LNG demand

15

Chinese LNG import capacity set to increase rapidly

Chinese regasification capacity should increase from ~21 bcm in 2011 to ~60 bcm in 2015, of which > 85% already is under construction

Based on proposed projects, import capacity could reach more than 100 bcm/year by 2020

Source: Interfax; IEA; Pareto

Chinese regasification capacity 2010, 2015e and proposed

21

60

0

20

40

60

80

100

2011 2015e 2015e + totalproposed

China LNG import capacity (bcm/year)

> 100

16

Gas penetration in China increases from a very low level

The Chinese government aims to increase the share of gas in total energy demand from 4% in 2010 to 8% in 2015 and 10% in 2020

There would still be plenty of upside compared with the world ex-China

A strong supply side supports increased gas use

Domestic production (shale)

LNG imports

Pipeline imports

Source: BP; IEA; Pareto

The share of gas in total energy demand

4%

8%10%

0%

5%

10%

15%

20%

25%

30%

2010 2015 target 2020 target

Gas share of total energy demand

China World ex-China 2010

World ex-China 2010: 29%

17

A substantial amount of LNG is needed to meet increasing Chinese gas demand

A sharp increase in LNG imports are needed, even if one assumes rapid growth in domestic production and pipeline imports

Assumptions

Demand and shale in line with government targets

Conventional production CAGR of 4.5%*

Pipeline imports: CACP (40 bcm) + Myanmar (13 bcm) + CACP exp. (20 bcm)

*ConocoPhillips/Wood Mackenzie estimates Source: BP; IEA; ConocoPhillips; Pareto

Chinese gas demand and supply by source 2010, 2015e and 2020e

97135 150

7

8046

97

63

73

0

50

100

150

200

250

300

350

400

450

2010 2015e 2020e

Chinese gas demand and supply by source (bcm)

Pipeline imports LNG imports Shale prod. Conventional prod.

109

250

400

18

What do E&P companies say about shale gas outside of US?

Chevron (exploring for shale in China, Poland, Bulgaria, Romania and Ukraine)

The speed at what people speculate shale gas will be coming to market is too fast

There is a huge difference between the US and the rest of the world:

There have been millions of wells drilled in the US

You know a lot more about the actual geology

No other place in the world that has such a well-developed gas infrastructure

CNPC, China’s largest gas producer

Compared with North America, China’s shale gas resources involve more complicated geological features. “The geological conditions are very different from North America”, CNPC geologist

Water scarcity is a challenge. CNPC pursues reduced-water and no-water fracturing technologies

CNPC says it is unable to meet the government’s shale gas targets. The company targets 1 bcm of shale gas production in 2015, compared with 2.5 bcm proposed by the government

Source: Interfax; Argus; Rigzone; Pareto

19

Japanese LNG imports should increase further in 2012 due to nuclear outages

The lost nuclear power equals

17 bcm in 2011

32 bcm in 2012 (IEA base case)

38 bcm in 2012 (no restart)

Growth y/y in LNG imports, assuming 60-65% of the nuclear loss is met by LNG

2011: 11 bcm (12%)

2012: 8-12 bcm (8-11%)

Source: IEA; Pareto

Japanese power generation scenarios April 2011 – December 2012

0

5

10

15

20

25

Apr-11 Aug-11 Dec-11 Apr-12 Aug-12 Dec-12

Japanese nuclear power generation (TWh)

Normal No restart IEA base case

20

Indian LNG needs should increase more than expected as domestic gas production disappoints

Gas production at India’s KG-D6 field is disappointing due to pressure drop and high water ingress

Current output is 11 bcm/yr, down from a high of 22 bcm/yr (in 2010) and well below the 29 bcm/yr targeted by 2012

Production may dip below 8 bcm/yr in 2013-2014

2P reserve estimate cut from more than 300 bcm (2006) to 55 bcm now

This is positive for LNG imports

LNG imports increased 41% to 17 bcm in 2011 and should be set for another sharp increase in 2012. The current KG-D6 shortfall equals ~100% of LNG imports

Regas capacity increases to 25+ bcm/yr by YE’12 and to 60+ bcm/yr by 2015/2016 based on proposed projects

Supports construction of additional regas capacity and new LNG supply contracts

Source: Interfax; The Times of India; BP; EIA; Pareto

KG-D6 production overview

Indian gas supply and demand 2010

Demand bcm/year 62

Domestic production " 51

of which KG-D6 " 20

LNG imports " 12

KG-D6 is key for Indian gas supply

KG-D6 production (started in April 2009)

2010 production bcm/year 20

June 2012 production " 11

March 2013 guiding " 10

2013-2014 guiding " 8

2012 origina l target " 29

*Output may dip below this level in 2013-2014 according to

Reliance

21

Liquefaction capacity should be set for growth

Projects under construction increases supply 4.6% p.a. through 2017

Proposed projects underpin further solid growth from 2015-2016

Even if 50% is cancelled, the rest is delayed by 3 years and no additional projects come on-stream, global LNG supply would increase by 6% p.a. on avg through 2024

*Not conclusive Source: IEA; Clarksons; Poten; Wood Mackenzie; Pareto

LNG liquefaction capacity outlook

331

134

566

1,030

0

200

400

600

800

1,000

1,200

Supply 2011 Under construction Proposed*(Pre-FID)

Total

LNG liquefaction capacity (bcm/year)

2

4

6

8

10

12

14

16

18

Jan-00 Jan-02 Jan-04 Jan-06 Jan-08 Jan-10 Jan-12

Japan LNG average price

USD/mmbtu

22

LNG prices support Final Investment Decisions (FIDs)

Source: Bloomberg; Wood Mackenzie; Pareto

Asian LNG prices 2000 – 2012 vs. Breakeven for new liquefaction projects

Breakeven for new liquefaction projects

Spot LNG in Asia has been in the USD 13-18/mmbtu range since Jun-11

23

2011 was a great year for liquefaction FIDs. More should be underway in 2012-2013

In 2011, five projects took FID: Donggi-Senoro, Gladstone, Prelude, AP LNG, and Wheatstone. Total capacity of 36 bcm/year

In 2012, Ichthys, AP LNG T2 and Cheniere have taken FID and there should be more underway over the next 18 months

Source: Company data; IEA; Pareto

Amount of liquefaction capacity taking FID 2007 – 2012 YTD

6

19

6

29

12

36

31

0

5

10

15

20

25

30

35

40

2006 2007 2008 2009 2010 2011 2012YTD

FIDtarget

'12-'13

Liquefaction capacity taking FID (bcm/year)> 160

24

Cheniere with FID on Sabine Pass - could require ~28 vessels

Construction of the phase 1 (first two trains) started in August 2012. First LNG expected in 2015

FID on phase 2 targeted in 2013. The project in total will up to 30 vessels shipping cargoes into Asia and Europe

*160,000 CBM Source: Cheniere Energy; Platts; Pareto

Overview of Sabine Pass liquefaction project in Louisiana, US (Cheniere Energy)

Sabine Pass (Cheniere Energy)

Phase 1 Phase 2 Total

Capacity bcm/year 12.2 12.2 24.5

Definitive commercial agreements " 10.5 11.3 21.8 - BG " 5.7 1.8 7.5

- Gas Natural Fenosa (Spain) " 4.8 - 4.8

- GAIL (India) " - 4.8 4.8

- KOGAS (Korea) " - 4.8 4.8

Spot/Flexible " 1.7 0.9 2.6

Start-up target Year 2015-2016 2017-2018 2015-2018

FID target " 2012 2012-2013 -

Shipping demand (Pareto est.) # of vessels* 12 16 28

25

Increasing interest in US LNG

Cheniere has started construction

Mitsui, Mitsubishi and GDF Suez have agreed to buy 16 bcm/yr from Cameron (not-final). Targets construction start late 2013, with first LNG late 2016

Chubu Electric Power and Osaka Gas signed agreements to buy 6 bcm/year combined from Freeport

*Cheniere shipping demand is based on the signed sales contracts. For the other projects, Asia is assumed as the destination (using the Panama canal). 160,000 CBM vessel size **The agreements with Mitsubishi, Mitsui and GDF Suez bind the parties to fund all development expenses, including design, permitting and engineering, as well as to negotiate 20-year tolling agreements Source: Company data; Platts; IEA; Bloomberg; Pareto

US liquefaction projects (not conclusive)

Project Location Capacity Ship demand* Comment

(bcm/year) (# of vessels)

Freeport Texas 18 25

Cameron LNG Louisiana 16 23 Agreements with Mitsui, Mitsubishi and GDF Suez**

Dominion Cove Point Maryland 11 19

Cheniere Energy Louisiana 24 28 Construction expected to start in 2012

Other proposed projects

Lake Charles Louisiana 21 29

Jordan Cove Energy Oregon 8 5

Corpus Christi Texas 18 26

Lavaca Bay LNG (FLNG) US GoM 4 6

Total 121 161

26

Increasing interest in US LNG II

North American LNG projects overview

US firm State bcm/y mtons/a Start Filed DOE

Sabine Pass T 1&2 US, Louisiana 12.2 9.0 2015-2016 Approved

US proposed State bcm/y mtons/a Start Filed DOE

Sabine Pass T 3&4 US, Louisiana 12.2 9.0 2017-2018 Aug-10

Freeport US, Texas 18.0 13.2 2015+ Dec-10

Lake Charles (Trunkline LNG) US, Louisiana 20.7 15.2 2015+ May-11

Cameron LNG US, Louisiana 16.3 12.0 Late 2016 Nov-11

Jordan Cove Energy US, Oregon 8.2 6.0 2018+ Sep-11

Dominion Cove Point US, Maryland 10.6 7.8 2018+ Sep-11

Corpus Christi US, Texas 18.4 13.5 2017+ FERC Dec-12

Southern LNG (Elba Island) US, Georgia 5.4 4.0 2020 May-12

Golden Pass US, Texas 21.2 15.6 2018 Aug-12

Warrenton LNG US, Oregon 12.2 9.0 2018+ May-12

Gulf Coast LNG US, Texas 28.9 21.3 2018+ Dec-11

Pascagoula US, Mississippi 15.0 11.0 2018+ May-12

Lavaca Bay LNG (FLNG) US GoM 4.1 3.0 2017+ May-12

Total US - 191.2 140.6

Canada proposed State bcm/y mtons/a Start

Kitimat T1 Canada 6.8 5.0 2015+

BC LNG T1 Canada 1.2 0.9 2013-2014

BC LNG T2 Canada 1.2 0.9 2016-2018

Progress LNG 1 Canada 5.0 3.7 2016+

Progress LNG 2 Canada 5.0 3.7 2020

Canada LNG, T1-2 Canada 16.3 12.0 2019

Canada LNG, T3-4 Canada 16.3 12.0 2020++

Total Canada - 51.9 38.2

North American LNG projects overview

27

North American liquefaction projects – a potential game changer

Dominion Cove Point

Lake Charles

Cameron LNG

Jordan Cove Energy

Freeport

Sabine Pass

Corpus Christi

In total, we see 17 potential US liquefaction projects

Start-up beyond 2015

Most of the US liquefaction projects are located in the Gulf

Given that a majority of the volumes are likely to be shipped into Asia, the US projects are very ton-mile intensive

Not conclusive

Progress LNG

Southern LNG Golden Pass

Lavaca Bay

Kitimat / BC LNG /

Canada LNG

28

US LNG and export permissions

A main obstacle for the projects is obtaining export permission to countries with which the US does not have a free trade agreement (FTA)

The exception is Cheniere which already has received a non-FTA export permission for 22 bcm/year

Non-FTA export permission is key as, except South Korea, none of the current FTA countries are large LNG importers

In the near term, the US Department of Energy (DoE) has suspended approval of new non-FTA export permissions as the potential impacts of US LNG exports is assessed

A report investigating the impact on the US economy expected to be finished by YE’12 is important

No decision likely before 2013

It should be noted that EIA in January published a report on the “Effect of Increased Natural Gas Exports on Domestic Energy Markets”.

The report was requested by DoE as one input to their assessment of the impact of LNG exports

The report estimated that LNG exports would have a fairly low impact on the US gas price *

*In the reference scenario with no LNG exports, the Henry Hub price was estimated to average USD 5.2/mmbtu in 2015-2025. In a scenario where LNG exports increase gradually from zero in 2014 to 61 bcm in 2020 and remains at 61 bcm thereafter, the Henry Hub price would average USD 5.7/mmbtu in 2015-2025 Source: EIA; Interfax; Pareto

29

Liquefaction projects pre-FID


Project Country Capacity (bcm/yr) Start up Project Country Capacity (bcm/yr) Start up

Angola LNG Tra in 2 Angola 7.1 2015+ Mozambique LNG (ENI) Mozambique 10.0 2020

Pluto T2 Austra l ia 6.8 2016 Brass LNG Nigeria 6.8 2016

Pluto T3 Austra l ia 6.8 2018 Olokola LNG Nigeria 15.0 2018+

Newcastle LNG Austra l ia 1.4 2015 NLNG Tra in 7 Nigeria 11.4 2018+

Browse Austra l ia 16.3 2017+ Snøhvit T2 Norway 5.6 2018+

Arrow Austra l ia 10.8 2016+ Gulf LNG (FLNG) PNG 2.7 2015+

Sunrise (FLNG) Austra l ia/Timor 5.4 2016+ PNG LNG Tra in 3&4 PNG 9.0 2017+

Bonaparte FLNG Austra l ia 2.7 2018 PNG FLNG PNG 4.1 2016

Gorgon T4 Austra l ia 6.8 2017+ Shtokman Russ ia 10.2 2020+

Wheatstone T3-4 Austra l ia 13.6 2018+ Sakhal in II T3 Russ ia 6.5 2015+

Qld Tra in 3 Austra l ia 5.8 2017+ Sakhal in I Russ ia 7.5 2015+

PTTEP Floater (FLNG) Austra l ia 3.4 2017 Sakhal in II I Russ ia 7.5 2015+

Santos FLNG Brazi l 3.7 Delayed Vladivostok LNG Russ ia 13.6 2017+

Kribi LNG Cameroon 4.8 2017+ Yamal LNG Russ ia 20.4 2017+

Kitimat T1 Canada 6.8 2015+ Pechora Russ ia 3.5 2020+

BC LNG T1 Canada 1.2 2013-2014 Tanzania LNG Tanzania 10.0 2018+

BC LNG T2 Canada 1.2 2016-2018 Sabine Pass T 3&4 US, Louis iana 12.2 2017-2018

Progress LNG 1 Canada 5.0 2016+ Freeport US, Texas 18.0 2015+

Progress LNG 2 Canada 5.0 2020 Lake Charles (Trunkl ine LNG)US, Louis iana 20.7 2015+

Canada LNG, T1-2 Canada 16.3 2019 Cameron LNG US, Louis iana 16.3 Late 2016

Canada LNG, T3-4 Canada 16.3 2020++ Jordan Cove Energy US, Oregon 8.2 2018+

EG LNG Tra in 2 Equatoria l Guinea 6.0 2016+ Dominion Cove Point US, Maryland 10.6 2018+

Tangguh T3 Indones ia 5.2 2014+ Corpus Chris ti US, Texas 18.4 2017+

Masela Tra in 1 (Abadi LNG, FLNG)Indones ia 3.4 2018+ Alaska LNG US, Alaska 20.4 2020

Masela Tra in 2 Indones ia 2.7 2018+ Southern LNG (Elba Is land)US, Georgia 5.4 2020

Mahakam (Bonatang) Indones ia NA 2017+ Lavaca Bay LNG (FLNG) US GoM 4.1 2017+

Iraq LNG Iraq 5.4 2017-2018 Delta Caribe Oriental 1 Venezuela 6.4 2015+

Israel LNG (Tamar) Is rael 2.7 2018+ Delta Caribe Oriental 2 Venezuela 6.4 2015+

Petronas LNG Tra in 9 Malays ia 4.9 Q4'15 Delta Caribe Oriental 3 Venezuela 6.4 2015+

Mozambique LNG (APC) Mozambique 13.6 2018+ Total proposed 565.8

Liquefaction projects pre-FID Liquefaction projects pre-FID

30

Liquefaction projects in ramp up or under construction


Project Country Capacity (bcm/yr) Start up

Pluto Tra in 1 Austra l ia 5.8 Mar-12

Wheatstone Austra l ia 12.1 2016

Angola LNG Angola 7.1 Q2'12

Arzew Algeria 6.4 2014

Skikda replacement Algeria 6.1 2014

PNG LNG Tra in 1&2 PNG 9.0 2014

Qld Tra in 1-2 Austra l ia 11.6 2014

Gladstone LNG Austra l ia 10.6 2015

Donggi -Senoro Indones ia 2.7 2014

Gorgon T1 Austra l ia 6.8 2014



Prelude (FLNG) Austra l ia 4.8 2016

AP LNG T1 Austra l ia 6.1 2015

Ichthys Austra l ia 11.4 2017

AP LNG T2 Austra l ia 6.1 2016

Sabine Pass T 1&2 US, Louis iana 12.2 2015-2016

Petronas FLNG Malays ia 1.4 2015

Total 133.8

Liquefaction projects under ramp up/construction

LNG shipping and FSRU outlook Approaching peak winter season

October 2012

Please refer to important disclosures at the end of this document

Per Kristian Reppe Direct: +47 2413 2187


Jonas Kraft Direct: +47 2413 2188


mailto:[email protected]

mailto:[email protected]

32

Recent newsflow and comments

Very few orders placed

Highlights

14 LNG carriers ordered YTD

Very slow order intake for yards in Q2, only 3 orders placed (Brunei Gas Carriers / MOL)

Financing is an issue: speculative players have increasingly difficulty getting financing for growth

Orderbook vs. incremental demand

Spot rates negatively affected recently

Spot rates have been negatively impacted by seasonality and more available tonnage in July

The Angola liquefaction plant continues to be delayed; now expected in operation in early Q4

About ~10 vessels have entered the spot market on short term employment / no employment

Expect a pick-up in rates into Q4

The summer months are usually a slow period in terms of shipments of LNG cargo

Charterers likely to soon start positioning ahead of the winter season

Expect to see rates picking up in Q4 with more spot volumes being demanded in Asia

2011: Rates moved from USD 100,000 per day in October to USD 150,000 in December

Top picks / rec.

We believe the winter market looks increasingly tight this year

Buy the players with spot exposure: Golar LNG and Awilco LNG

Buy Höegh LNG on new FSRU awards

Total orderbook now stands at 77 units or 22% of existing fleet

Liquefaction capacity out of US included in estimates: Cheniere with FID on Sabine Pass T 1-2

New liquefaction capacity exceeds current orderbook, but 2014/2015 still likely to see lower rates

Overview of the LNG value chain

LNG value chain 101:

Natural gas in its original form is cooled down to liquid form at dedicated plants

The liquefied gas is then shipped to its destination, converted to gas again and distributed to the consumer

Source: Pareto

LNG value chain

33

Production Liquefaction Regasification Offtake

Onshore

Offshore

Liquefaction Plant

Regas Terminal Power Plant

LNG FPSO FSRU Gas-To-Wire LNGC Platform/ Installation

Shipping

34

Summary

More hardware is needed to meet the growing demand for LNG!

Undersupply of ships in 2012-13, utilization above 90% in 2014-15 if all options gets exercised, hence rates will continue to increase short to medium term

Demand for up to 180-370 new vessels by 2020, subject to liquefaction FID’s

The number of LNG importing countries will double by 2015, hence demand for Floating Storage and Regasification units will continue to grow at a strong pace

Main driver and main risk to both shipping and FSRU demand is liquefaction capacity

Source: Pareto Securities

35

LNG fleet growth rising through 2014

*Source: Pareto Securities, World Yards, Clarksons

LNG fleet growth, y/y (mcbm) and number of vessels

Growth rate accelerated from 2003 until 2010 with 197 net deliveries.

Supply growth exceed demand growth every year

On the back of turmoil in financial markets and lack of financing the growth rate declined significantly in 2010 and 2011.

Few, if any, available slots for 2014. Hence, it is not possible to add any incremental supply before 2015

Engines seems to be the bottleneck

0%

5%

10%

15%

20%

25%

0

50

100

150

200

250

300

350

400

450

500

2001 2003 2005 2007 2009 2011 2013 2015

Number of vessels Y/Y growth CBM

# vessels Y/Y fleet growth

36

Firm vessels in the orderbook represent 22% of the existing fleet


LNG fleet growth, y/y (mcbm) and number of vessels

355 367 369 390 422 441 444

11.3%

4.8%

1.7%

3.3%

7.5% 6.9%

2.8%

0%

2%

4%

6%

8%

10%

12%

0

50

100

150

200

250

300

350

400

450

500

2010 2011 2012 2013 2014 2015 2016

Number of vessels Y/Y growth CBM

# vessels y/y fleet growth

Current LNG fleet stands at 368 units (above 3,000 dwt)

The orderbook comprises 77 firm vessels (11.9m cbm) ex. 6 FSRU

In addition, we estimate that there is about 26 options outstanding, but difficult to be exact

Orderbook including options at 29.8% of the current fleet (mcbm)

37

Fleet growth is however low compared to the historical levels

Current firm orderbook points to a fleet growth CAGR of 5.1% in the period from 2011 to 2015

In comparison, fleet growth averaged 13.3% and 14.2% in the period 2001-11 and 2005-11, respectively


Historical fleet growth vs. current orderbook

13.3%14.2%

5.1%

0%

2%

4%

6%

8%

10%

12%

14%

16%

CAGR 2001-11 CAGR 2005-11 CAGR 2011-15

Fleet growth (excluding options)

Fleet growth %

38

New orders will be placed for 2015 deliveries

*Source: Pareto Securities, Clarksons, World Yards

LNG deliveries and yard capacity

1015

20 1927

32

4638

1812

11

21

32

19

3

26

42

0

5

10

15

20

25

30

35

40

45

50

Deliveries Orderbook Options Excess capacity

# vessels Current orderbook counts 77 vessels, or roughly 22% of the total fleet (cbm)

About 40% will be delivered in 2014, next open slots are for 2015 deliveries

Delivery capacity is about 45 vessels per annum, of which the top-end Korean yards hold a 80% market share

About 50% of the orderbook already fixed to E&P players

Gazprom

BG Group

Shell

Woodside

Chevron

Brunei / Exxon / Osaka Gas / PNG

39

Very few orders placed YTD

*Source: Pareto Securities, Clarksons

LNG vessel orders placed by year

710

15

20 21 2015

70

48

36

26

50

7

52

15

0

10

20

30

40

50

60

70

80

1996 1998 2000 2002 2004 2006 2008 2010 2012

# orders

2011 was a big year for LNG vessel orders with 52 places after only 12 orders between 2008-10

2012 YTD 15 LNG carriers have been ordered at Korean and Japanese yards

High activity in Q1

Virtually no activity in Q2, stand still among the speculative players (Brunei and MOL placing 3 orders for back-to-back projects)

Financing is an issue: speculative players have increasingly difficultly getting the necessary equity/debt financing

40

Undersupply of vessels already back in 2011

Source: Pareto Securities, Fearnleys LNG

Vessel availability spot market and LNG rates

0

20

40

60

80

100

120

140

0

5

10

15

20

25

Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11

LNG carrier availability

Available vessels (lhs) LNG spot rate

Vessel availability in the spot market has been very tight over the last one and a half year

This correlates well with the rally we have seen in rates

Average availability was below 3 over 2011 in the spot market

Industry players talk about 5 – 15 vessels in deficit in 2011

41

Shipping: very tight market balance in 2012-13

Source: Pareto Securities, IEA, World Yards

LNG vessel surplus / deficit*

-10-12

-8

15

2622

2

-6 -5 -4

-20

-10

0

10

20

30

40

2011 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

# of vessels

We estimate that the market was in deficit with 10 vessels in 2011

We expect the market to remain undersupplied in both 2012 and 2013, but slightly softer in 2014 through 2016

Fleet utilization likely to stay above 90% in 2014-16 based on current orderbook and unexercised options which points to a continued good market ahead

*Our surplus / deficit calculations takes into account the existing orderbook, a declining ton mile effect from new Australian projects as well as a decline in existing production

42

Solid upside in shipping demand from new liquefaction projects


LNG vessel orderbook versus liquefaction capacity additions

*net of a 4% decline in existing capacity. Assumes 92% capacity utilization

Current LNG vessel orderbook constitutes 22% of the current fleet and 29% including options

According to our data, growth in liquefaction capacity from projects under construction plus ramp-up is at 32%, higher than the fleet orderbook

Adding liquefaction projects with FID in 2012-13 we see demand increasing with another 50%

Adding all liquefaction projects which have currently been proposed, would add another 87% to the LNG vessel volume demand

25%

7%32%

50%

107%

0%

20%

40%

60%

80%

100%

120%

140%

160%

Supply (Orderbook) Demand (Liquefaction capacity*)

Orderbook relative to 2011 level

Liquefaction capacity: Additional proposed Liquefaction capacity: FID target 2012-2013

Liquefaction capacity: Under cons./Ramp up Orderbook: Options

Orderbook: Firm

43

More liquefaction FID’s points to increased vessel demand


LNG vessel surplus / deficit

-58-81

-138

-211-250

-200

-150

-100

-50

0

50

2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

# of vessels

Capacity under construction + 50% of proposed

While investment decisions for liquefaction plants up until 2016 have already been set, we believe more capacity has to be added in order to avoid shortage of LNG

Assuming that 50% of the liquefaction projects currently planned gets FID, we see a total need for another 211 new vessel by 2020

44

High case: we could see demand for 365 new orders by 2020


LNG vessel surplus / deficit

-58-81

-138

-211

-117-156

-270

-418-450

-400

-350

-300

-250

-200

-150

-100

-50

0

50

2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

# of vessels

Capacity under construction + 50% of proposed + 100% of proposed

If we assume that all liquefaction projects on our list get FID, we see demand for an additional 418 vessels by 2020

However, it is not likely that all projects get FID due to current financial environment and funding risk

On the other hand, almost all projects last year got FID despite the turmoil in the second half of 2011

New projects which are not included in our project list are also likely to surface

45

Market balance summary

*Assumes 92% utilization of liquefaction capacity. Demand from projects under construction takes ton-mile effects into account. Demand from proposed projects assumes 1 vessel per 1 bcm/year Source: BP; IEA; Poten; Wood Mackenzie; Golar; Pareto

LNG trade and shipping market balance 2011 – 2020e

Projects under construction

LNG trade and shipping balance 2011 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

LNG trade* bcm/year 331 339 344 348 377 402 434 446 445 444

Increase from 2011 bcm/year 8 13 17 47 71 103 115 115 113

Ship demand* # of vessels 371 380 388 391 406 420 442 450 449 448

Fleet (current orderbook) " 361 368 380 406 432 443 444 444 444 444

Ship surplus/defici t " -10 -12 -8 15 26 22 2 -6 -5 -4

Fleet uti l i zation ex.options 103% 104% 102% 96% 94% 95% 100% 101% 101% 101%

Fleet uti l i zation inc. options 103% 104% 102% 96% 91% 89% 94% 95% 95% 95%

Projects under construction and 50% of proposed capacity






Ship surplus/defici t " -10 -12 -8 15 25 12 -58 -81 -138 -211

Fleet uti l i zation 103% 104% 102% 96% 94% 97% 114% 120% 134% 151%


Projects under construction and 100% of proposed capacity






Ship surplus/defici t " -10 -12 -8 15 24 2 -117 -156 -270 -418

Fleet uti l i zation 103% 104% 102% 96% 94% 100% 128% 138% 166% 202%


46

Fleet utilization will stay high


LNG fleet utilization based on firm supply and demand

103% 104% 102%96%

94% 95%100% 101% 101% 101%

91% 89% 94% 95% 95% 95%80%

100%

120%

140%

160%

180%

200%

2011 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Fleet util ization

Capacity under construction Incl options

Based on current liquefaction capacity under construction and fleet on order, capacity utilization stays above 94% through 2020

In shipping you have a good market if capacity utilization is above 90%

If capacity utilization is above 92-93% you have a booming market

47

Fleet utilization will stay high


LNG fleet utilization (50%/100% of proposed capacity)

If 50% of all LNG liquefaction projects currently planned get FID, LNG fleet capacity utilization rises to a hypothetical 151%

If 100% of all LNG liquefaction projects currently planned get FID, LNG fleet capacity utilization rises to 202% given no new orders

Several liquefaction projects have FID in 2012 and 2013, which clearly illustrates that the need to build more LNG vessels to meet demand in the second half of the decade

104% 102% 96%94% 97%

114%

120%

134%

151%

128%138%

166%

202%

80%

100%

120%

140%

160%

180%

200%

2011 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Fleet util ization

Capacity under construction + 50% of proposed + 100% of proposed

48

Older tonnage likely to be phased out for scrapping and potentially conversions into FSRUs

Few vessels in lay-up; unlikely to re-enter the market

Over 40 vessels are older than 30 years:

This is 9% of the total market

Or approximately 29 newbuilds

The oldest 1st generation vessels are already starting to be scrapped

Over 30+ FSRU projects expected within 2015

Only 2 uncommitted FSRU newbuilds in the orderbook (but the players have options outstanding)

*Source: Pareto, World Yards

Age distribution LNG fleet

31 0 1 1 2

53

7 6 53

6

14 4

1 0 0 03 2 1 1

58

58

6 5 6

13

1

1014

2019

27

33

52

40

23

12

0

10

20

30

40

50

60

1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009

LNG fleet - age distribution

Age distribution

Scrapping candidates

49

Few vessels in lay-up


LNG vessels in lay-up

LNG vessels in layup

No Name Built Capacity (cbm) Owner Comment

1 Galeomma 1978 126,540 Shell Anchored

2 Tenaga Tiga 1981 130,000 Petronas Anchored

3 Tenaga Dua 1981 130,000 Petronas Anchored

4 LNG Palmaria 1969 41,000 Eni Very old, not likely to return

5 Koto (Kotowaka Maru) 1984 125,000 BW Gas Flooded engine room, severe damage

Only five vessels are currently in lay-up

Several older vessels have now returned to the market. Examples include among others Gimi, Hilli and Gandria to Golar

50

Who can meet demand?

*Source: Pareto Securities, Clarksons, World Yards

LNG orders by yard

24

15 18

5 5 6 4

2

1

3

0

5

10

15

20

25

30

Samsung Daewoo Hyundai Hudong Mitsubishi STX Kawasaki

LNG firm FSRU firm

# vessels

The three top end yards in Korea (Samsung, Daewoo and Hyundai) have the highest number of vessels on order

China will eventually build, but currently only has one shipyard (Hudong) with vessels on order

However, the technology aspects limits significant supply expansion. Moreover, the high capex commitment limits speculative orders to a large extent

51

LNG trade is driven by liquefaction capacity and not GDP growth

The driver for growth in LNG trade is new liquefaction capacity and not GDP growth

As an example, LNG trade increased 7.2% in 2009 despite a 0.6% decline in world GDP

Source: IMF; BP; Pareto

World GDP growth vs. World LNG trade growth 2001 – 2011

4.4% 4.9%

12.6%

5.4% 6.1%

11.8%

7.3%

0.0%

7.2%

22.6%

9.6%

-5%

0%

5%

10%

15%

20%

25%

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

World GDP and LNG trade growth y/y

World LNG trade growth y/y World GDP growth y/y

52

A spot market is evolving


Short term versus long term LNG shipping contracts

130 132 139 153 158 165 178 182 187 203241 248

11 1116 20 24

34 45 4040

5684

0

50

100

150

200

250

300

350

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Long term contracts Spot and short term trade (incl. contracts < 4 yrs)

Global LNG trade (bcm)

A concern in LNG shipping is that building liquefaction is so expensive that vessel order will be placed back to back with large projects

While this is true, we have also seen a trend of increasing short term volumes

Whereas short term contracts under four years accounted for only 5% of the volumes in 2000, this had risen to 29% in 2011

An increasing number of regas terminals will also lead to a more liquid market

53

What is left on the table to cover TC cost and profit?

Source: Pareto Securities, Platts

Cost calculation, LNG cargo Middle East to Europe

10.0

1.0 1.0

0.5 0.8

6.7

3.0

3.7

0.0

2.0

4.0

6.0

8.0

10.0

12.0

USD/mmbtu

The example to the left illustrates the cost structure of shipping LNG from the Middle East to Europe

The gas is sold at USD 10/mmbtu

Cash cost to lift the cargo is USD 6.7/mmbtu. Including capex cost of liquefaction ,we estimate profits of USD 3.7/mmbtu ex. TC cost for the cargo owner

54

What is left on the table to cover TC cost and profit?


Cost calculation, LNG cargo Middle East to Japan

15.0

1.0 1.0

0.5 1.0

11.5

3.0

8.5

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

USD/mmbtu

The same exercise can be made with cargoes moved from the Middle East to Japan

Selling the cargo at USD 15/mmbtu, there is USD 8.5/mmbtu on the table to cover profit for the cargo owner plus TC cost and profit for the shipowner

55

Upside potential in rates


Profit left to cover profit for cargo owner

313

763

0

150

300

450

600

750

900

USDk/day

USD 3.7/mmbtu on a Middle East to Europe cargo equates to USD 313k/day on a roundtrip basis

USD 8.5/mmbtu on a Middle East to Japan cargo equates to USD 763k/day on a roundtrip basis

While TC rates will not increase to these levels as cargo owners need profits, we believe the levels say something about the upside potential on rates in a tight shipping market

56

Upside potential in rates


Profit left to cover profit for cargo owner

The same exercise can be done on other important LNG cargo routes

With current spot TC rates at USD 127k/day, there should be plenty of upside on rates going forward before we enter a scenario with rates destructing demand

Also keep in mind that traders could utilize the arbitrage opportunities in the market itself as long as there is upside on rates from current spot

313,000

763,000

218,000

607,000

336,000

127,0000

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

USD/day

57

Returns have never been higher


Capex/EBITDA (yrs) – 1yr contract

Returns are currently on all-time high in the LNG shipping space

Capex/EBITDA on a downward trajectory since mid-2010 driven by higher rates while newbuild prices have stayed flat

EBITDA 3yr charter in LNG shipping puts the CAPEX/EBITDA payback at 4.5 years, the lowest observed in all major steel segments

180

200

220

240

260

280

300

0

5

10

15

20

25

30

35

Jan-06 Oct-06 Aug-07 Jun-08 Mar-09 Jan-10 Nov-10 Aug-11

Capex, USDmCAPEX/EBITDA

CAPEX/EBITDA (yrs) LNG newbuild prices

58

Recent drop in spot rates, expect a pick-up in Q4

Source: Pareto Securities, Fearnleys LNG

LNG spot and term rates 138-145,000 cbm

Spot rates have dropped in July on the back of:

Seasonality (less demand)

The Angola liquefaction plant continues to be delayed

More available tonnage: Gandria, Hilli, WilPower, 5 Angola vessels

Current spot rates USD 127k/d with 1yr TC at USD 148k/d

Expect a strong period ahead – no unfixed vessel deliveries, few vessels in lay-up and seasonal strength through inventory build-up ahead of the winter

148,000

127,000

140,000

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

Jan Feb Mar Apr May June Jul Aug Sept Oct Nov Dec

Spot rates 2011/12 1yr TC rate 2011/12 3 yr TC

USD/d

59

FSRU: A new concept

Source: HLNG, Pareto Securities

Shuttle and Regasification Vessel

An FSRU stands for a Floating Storage and Regasification terminal

A regasification terminal converts LNG into gas before it goes into a pipeline system

Terminals can be built both on- and offshore. The advantages with offshore solutions are:

A floating solution is cheaper than an onshore installation (50% est.)

Upfront capex is lower

“Not-in-my-backyard” problems are avoided

The unit can be moved if needed

Time to market is quick

60

Floating regas: the obvious solution

Source: Pareto Securities, BP

LNG trade and FSRU share of the market

World demand for gas is expected to rise significantly over the next 10-20 years and LNG share of the total volumes should continue to increase

In our view, floating regas solutions is the obvious solution to meet energy demand in a flexible and cost efficient way

Floating regas is expected to comprise 11% of the total LNG volumes in 2015

0% 1%3% 3%

5%

8%

11% 11%

0%

5%

10%

15%

20%

25%

30%

0

50

100

150

200

250

300

350

400

2008 2009 2010 2011e 2012e 2013e 2014e 2015e

LNG volumes ex FSRU FSRU volumes FSRU % of LNG

World demand, bcm/year FSRU share of total

61

Only three established players in the market


Current FSRU fleet

The market comprises only three established players:

Excelerate Energy (8 vessels)

Höegh LNG (2 vessels)

Golar LNG (4 vessels)

15 vessels are currently in operation worldwide

Barriers of entry is high (technology, know-how, relationships, brand and capital)

Difficult for new players to enter into the market. Energy utilities seem to prefer established players

# Vessel Regas type Capacity Built Owner

1 GDF Suez Neptune Newbui ld - shuttle 145,130 2009 Lei f Hoegh/Mitsui OSK

2 GDF Suez Cape Ann Newbui ld - shuttle 145,130 2010 Lei f Hoegh/Mitsui OSK

3 Golar Spiri t Convers ion - s tatic 129,013 1981 Golar LNG

4 Golar Freeze Convers ion - fixed 125,800 1977 Golar LNG

5 Golar Winter Convers ion - s tatic 138,000 2004 Golar LNG

6 Khannur Convers ion - fixed 125,003 1977 Golar LNG

7 Excel lence Newbui ld - shuttle 138,120 2005 GFK/Excelerate

8 Excelerate Newbui ld - shuttle 138,074 2006 Exmar/Excelerate Energy

9 Excels ior Newbui ld - shuttle 138,060 2005 Exmar/Teekay/Excelerate

10 Explorer Newbui ld - shuttle 150,981 2008 Exmar/Excelerate Energy

11 Express Newbui ld - shuttle 150,900 2009 Exmar/Excelerate Energy

12 Exquis i te Newbui ld - shuttle 150,900 2009 Excelerate Energy

13 Expedient Newbui ld - shuttle 150,900 2010 Excelerate Energy

14 Exemplar Newbui ld - shuttle 150,900 2010 Excelerate Energy

15 FSRU Toscana Convers ion - fixed 137,000 2004 OLT Offshore LNG Toscana

62

Rapid expansion of FSRU projects worldwide


First FSRU came in operation in 2005 in the US (Gulf Gateway). The terminal was recently closed down due to low gas imports in the US

Since then we have seen a rapid expansion of new floating regas projects worldwide

Today there are 10 operational projects and 12 more under construction /awarded. Projects under construction are expected onstream by 2012 through 2015

All projects have secured an FSRU

Regasification projects

63

A solid pipeline of FSRU projects


Regasification projects

We count further 8 FSRU projects somewhere in pipeline to take FID, none have secured an FSRU yet:

1x Argentina (Enarsa)

1x Indonesia (Pertamina)

1x Uruguay (UTE/Ancap)

1x Bahrain (Bapco)

1x Bangladesh (PetroBangla)

1x Abu Dhabi (Government)

1x Lebanon (Government)

1x India (Petronet)

We see about 30-35 potential FSRU awards within 2015. Industry players talk about 30+ potential projects

64

The Central Java conversion project more firm


Overview of LNG regas infrastructure in Indonesia

Earlier this year, PGN and Pertamina put the Central Java FSRU on hold due to the relocation of Höegh LNG’s first FSRU

According to HLNG, the Indonesian government has recently decided to continue the construction of the Central Java FSRU

This is a conversion project where HLNG and GLNG are shortlisted:

HLNG has offered the LNG Libra as a conversion candidate

HLNG - Original location for FSRU 1, Medan

HLNG - New location for FSRU 1, Lampung

GLNG - Nusantara Regas (Khannur) conversion, West Java

GLNG/HLNG – Central Java FSRU conversion (proposed)

65

HLNG selected as preferred bidder for the Colbun FSRU project

HLNG selected as preferred bidder

10+5 year

EBITDA USD 41m (vs. USD 50m exp)

Start-up late 2014

Valuation considerations

Capex to EBITDA 7.3x, slightly lower than 6.3x on the GasAtacama award to GLNG but clearly lower risk

Contract value USD 406m (NOK 7/sh)

NPV of contract value: USD 355m

Source: HLNG, Pareto

HLNG wins FSRU tender

66

Golar secures the long awaited GasAtacama FSRU contract


FSRU location in the Bay of Mejillones, Chile

Recently Golar LNG was awarded the much awaited Gas Atacama contact in Chile

Duration 15 or 20 years in the charters option, plus 3x5 optional years starting Q4’15

EBITDA guided to USD 47/48m (dayrate USD 150,000), well above our USD 39m expectation (dayrate USD 125,000)

IRR to capital > 15% assuming USD 300m in capex

However, more risk as we see it considering that GasAtacama has not sources the gas yet and higher counterparty risk

67

FSRU economics going through the roof


FSRU economics on selected contracts

We were impressed with the Lithuania contract awarded to Höegh LNG earlier this year

However, Golar’s Chile award sets a new benchmark in the space considering the length of the contract

EBITDA payback approaching six years on newbuilds with 35+ years of economic life and contract length in the range 15-20 years (ex. options)

IRR to capital > 15%

Typically IRR is between 12 – 15% on contract awards

FSRU economics GLNG Chile GLNG Khannur* HLNG Indonesia HLNG Lithuania HLNG Colbun

Type Newbuild Conversion Newbuild Newbuild Newbuild

Capex 300 210 325 325 300

EBITDA 47 43 40 50 41

Firm contract (yrs) 20 11 20 10 10

Option (yrs) 3x5 3 2x5 - 5

Capital structure:

Equity part 90 210 75 75 75

Leverage on asset 210 0 250 250 225

Total project cost 300 210 325 325 300

EBITDA payback (yrs) 6.4 4.9 8.1 6.5 7.3

IRR capital (%) 15% 19% 11% 12% 12%

* Capex includes conversion capex and alternative cost for asset (USD 50m)

68

Excelerate upping its stake in the orderbook with 8 FSRU options


Current FSRU orderbook

Current orderbook comprises 7 FSRU vessels:

Höegh: 3 units (2013/14e)

Golar LNG: 3 units (2013/14/15e)

Excelerate: 1 unit (2014e)

Five newbuilds are already committed to projects:

Höegh: Indonesia/Lithuania/Chile

Excelerate: Brazil (VT3 Petrobras)

Golar: Chile (Gas Atacama)

First open FSRU slot in H1’15

FSRU orderbook

# Vessel Regas type Capacity Built Owner Yard

1 SRV Newbui ld SRV 170,000 2013 Q4 Höegh LNG Hyundai



4 SRV Newbui ld 170,000 2013 Q4 Golar LNG Samsung


6 SRV Newbui ld 173,400 2014 Q2 Excelerate Energy Daewoo


8 option SRV Newbui ld SRV 170,000 2014 Høegh LNG Hyundai



11 option SRV Newbui ld 173,400 2015-17 Excelerate Energy Daewoo








On contract / preferred bidder

69

APPENDIX

70

LNG newbuilding costs at USD 200m ..but low order intake at yards may force the price down

Current quotes at ~USD 200m delivery in 2015 from Korean yards

Average newbuild cost at USD 220m

*Source: Pareto Securities, Clarksons

LNG newbuild cost

222

190

200

210

220

230

240

250

260

2007-01 2008-01 2009-01 2010-01 2011-01

160k cbm NB price Avg price

USDm

71

LNG vessel sales

*Source: Pareto Securities, Worldyards

Date Received Current Name/Hull NoCapacity

(cbm)Built Seller Buyer

Price (Million

USD)Shipbuilder

18-Oct-2011 Woods ide Donaldson 165,500 19-Oct-2009 A.P. Mol ler - Maersk Teekay n/a Samsung

18-Oct-2011 Maersk ras laffan 138,200 27-Apr-2004 A.P. Mol ler - Maersk Teekay n/a Samsung

18-Oct-2011 Maersk Marib 165,500 Apr-2008 A.P. Mol ler - Maersk Teekay n/a Samsung

18-Oct-2011 Maersk Methane 165,500 Feb-2008 A.P. Mol ler - Maersk Teekay n/a Samsung

18-Oct-2011 Maersk Magel lan 165,000 Apr-2009 A.P. Mol ler - Maersk Teekay n/a Samsung

18-Oct-2011 Maersk Arwa 165,500 Sep-2008 A.P. Mol ler - Maersk Teekay n/a Samsung

18-Oct-2011 Maersk Meridian 165,500 15-Jan-2010 A.P. Mol ler - Maersk Teekay n/a Samsung

27-Sep-2011 Muscat lng 145,494 Apr-2004 Mitsui OSK Lines , MOL Greek 185 Kawasaki

27-Sep-2011 Transgas 129,323 Dec-1977 Louis Dreyfus n/a n/a France-dunkerque

1-May-2011 LNG Libra 126,750 1979 MOL Höegh LNG 53

24-May-2011 Clearsky 173,000 2011 TMT Stena Bulk 260 Daewoo, DSME

24-May-2011 Crysta lsky 173,000 2011 TMT Stena Bulk 260 Daewoo, DSME

24-May-2011 Bluesky 145,700 2006 TMT Stena Bulk 170 Daewoo, DSME

23-Mar-2011 WilEnergy (ex Banshu Maru) 125,542 1983 J3 (MOL, NYK, K Line) Awi lco 24 Mitsubishi Heavy, MHI

23-Mar-2011 WilGas (ex Dewa Maru) 125,877 1984 Awi lco 24 Mitsubishi Heavy, MHI

23-Mar-2011 WilPower (ex Bishu Maru) 125,929 1983 Awi lco 24 Kawasaki Heavy

20-Mar-2011 Aseem 155,000 Sep-2009 India Lng Transport No 1 Kawasaki Kisen Kaisha, K Line n/a Samsung

19-Mar-2011 Ejnan 145,000 Jan-2007 NYK Line [NYK Group] Kawasaki Kisen Kaisha, K Line n/a Samsung

18-Mar-2011 Echigo Maru 125,814 Aug-1983 NYK Line / MOL / K Line Kawasaki Kisen Kaisha, K Line n/a Mitsubishi Heavy, MHI

14-May-2010 Koto 125,468 Jan-1984 NYK Line [NYK Group] BW Gas [BW Group] 10 Kawasaki

24-Jul -2008 Hoegh Gandria 123,512 Oct-1977 Hoegh Autol iners Bluewater Group 40 HDW

04-Apr-2008 Polar eagle 88,200 Jun-1993 Teekay Norwegian 115 Chita Works

04-Apr-2008 Arctic sun 89,089 Dec-1993 n/a Norwegian 115 Chita Works

11-Jan-2008 FSRU Toscana 137,000 16-Jun-2004 Golar LNG OLT Offshore 231 Hyundai Heavy, HHI

20-Dec-2007 Granatina 138,538 30-Dec-2003 Royal Dutch Shel l Golar LNG n/a Daewoo, DSME

07-Sep-2007 Charm junior 50,240 Sep-1971 Gaz De France Bluesky Navigation n/a Alstom

19-Feb-2007 Margaret Hi l l 87,600 Nov-1974 Hoegh Autol iners Maverick LNG n/a Moss rosenberg s tavanger

08-Sep-2006 Scf Arctic 70,213 22-Dec-1969 BG Group n/a n/a Kockums mekaniska

08-Sep-2006 Scf Polar 70,237 01-May-1969 BG Group n/a n/a Kockums mekaniska

23-Jun-2005 Methania 131,235 13-Oct-1978 Bocimar [CMB Group] Distrigas n/a Boelwerf - Temse

25-Mar-2004 Cinderel la 25,500 Mar-1965 Chemikal ien Seetransport TMT n/a Seine

72

LNG resale values

*Source: Pareto Securities

Annual EBITDA NPV EBITDA

3y avg TC,

USD/d USDm USDm 180 190 200 210 220 230 240 250

70,000 19 46 189 197 205 212 220 228 236 244

80,000 22 56 198 206 214 222 229 237 245 253

90,000 26 65 207 215 223 231 239 246 254 262

100,000 30 74 216 224 232 240 248 256 263 271

110,000 33 83 225 233 241 249 257 265 272 280

120,000 37 92 234 242 250 258 266 274 282 289

130,000 41 101 243 251 259 267 275 283 291 299

140,000 Current 44 110 252 260 268 276 284 292 300 308

150,000 48 119 261 269 277 285 293 301 309 317

160,000 Pareto est 52 128 270 278 286 294 302 310 318 326

170,000 55 137 280 287 295 303 311 319 327 335

180,000 59 146 289 297 304 312 320 328 336 344

190,000 62 155 298 306 313 321 329 337 345 353

200,000 66 164 307 315 323 330 338 346 354 362

Input

NB lead time, yrs 3.0

WACC 10.0%

OPEX, USD/d 13,000

G&A, USD/d 2,500

Drydock, USD/d 3,288

Total operating cost 18,788

Payment year 1 20%

Payment year 2 10%

Payment year 3 70%

Newbuilding price USDm

Imp

lied

resale

value

73

LNG secondhand values and implied resale values


Age Built

-3 2015 185 190 200 210 220 230 240 250

-2 2014 207 212 221 230 240 249 258 268

-1 2013 229 233 242 251 259 268 276 285

0 2012 251 255 263 271 279 287 295 303

1 2011 245 248 256 264 271 279 287 294

2 2010 238 242 249 257 264 271 279 286

3 2009 231 235 242 249 257 264 271 278

4 2008 225 228 235 242 249 256 263 270

5 2007 218 221 228 235 242 249 255 262

6 2006 211 215 221 228 234 241 247 254

7 2005 205 208 214 221 227 233 240 246

8 2004 198 201 207 213 220 226 232 238

9 2003 192 194 200 206 212 218 224 230

10 2002 185 188 193 199 205 210 216 222

11 2001 178 181 186 192 197 203 208 214

12 2000 172 174 179 185 190 195 200 205

13 1999 165 168 172 177 182 187 192 197

14 1998 158 161 166 170 175 180 185 189

15 1997 152 154 159 163 168 172 177 181

16 1996 145 147 152 156 160 164 169 173

17 1995 139 141 145 149 153 157 161 165

18 1994 132 134 138 142 145 149 153 157

19 1993 125 127 131 134 138 142 145 149

20 1992 119 120 124 127 131 134 137 141

Vessel value, USDm Implied resale value basis long

term rates

Implied

TC rate resale value

USD/d USDm

70,000 175

80,000 210

90,000 244

100,000 278

110,000 312

120,000 347

130,000 381

140,000 415

150,000 449

Input


WACC 10.0%

OPEX, USD/d 13,000

G&A, USD/d 2,500



Lifetime, years 35

Scrap value, USDm 19

Scrap price, USD/lt 644

74

LNG vessel returns


Implied Implied

Resale Newbuilding break-even break-even EBITDA Value basis

TC rate Market Price Order Price EBITDA multiple IRR (rem life) EBITDA multiple IRR (rem life) resale newbuild bss TC rate TC rates

USDm USDm USDm*** basis TC rate Basis TC rate basis TC rate Basis TC rate TC rate TC rate USDm USDm

70,000 294 210 16.3 5.2% 11.7 8.1% 104,500 79,400 18 175

80,000 294 210 13.7 6.6% 9.7 9.9% 104,500 79,400 22 210

90,000 294 210 11.7 8.0% 8.4 11.7% 104,500 79,400 25 244

100,000 294 210 10.3 9.4% 7.3 13.5% 104,500 79,400 29 278

110,000 294 210 9.1 10.7% 6.5 15.2% 104,500 79,400 32 312

120,000 294 210 8.2 11.9% 5.9 17.0% 104,500 79,400 36 347

130,000 294 210 7.5 13.2% 5.3 18.7% 104,500 79,400 39 381

140,000 294 210 6.9 14.4% 4.9 20.4% 104,500 79,400 43 415

150,000 294 210 6.3 15.7% 4.5 22.1% 104,500 79,400 46 449

160,000 294 210 5.9 16.9% 4.2 23.8% 104,500 79,400 50 483

170,000 294 210 5.5 18.1% 3.9 25.5% 104,500 79,400 53 518

180,000 294 210 5.2 19.4% 3.7 27.2% 104,500 79,400 57 552

Input


WACC 10.0%

OPEX, USD/d 13,000

G&A, USD/d 2,500



Lifetime, years 35

Scrap value, USDm 19

Scrap price, USD/lt 644

NewbuildResale

75

FLNG projects

*Source: Pareto Securities, Upstream, Market sources, Höegh LNG

Project Name Participants Country Status

Prelude LNG Shel l / SHI / Technip Austra l ia FID achieved

Cash Maple PTT Austra l ia Pre-FEED completed

Sunrise Woods ide / Shel l / ConocoPhi l l ips Austra l ia Under review

Santos Pre-sa l t GDZ Suez / Santos Austra l ia FID delayed post 2013

Caribbean coast Paci fic / Exmar Austra l ia Service agreement s igned

Abadi FLNG Inpex / Shel l Indones ia FEED to s tart end 2012

PNG FLNG Höegh / Petromin / DSME / CB&I Papa New Guinea In process

Gulf LNG Flex LNG / SHI / WorleyParsons / Kanfa Aragon Papa New Guinea Under review

Sarawak Kanowit Petronas Malays ia FID achieved

Sarawak Rotan Petronas / Murphy Malays ia On-going pre-FEED studies

Tamar FLNG Noble / HLNG / DSME Israel Pre-FEED completed

Gulf Exports Excelerate Energy USA On-going FEED

76

FSRU projects operational and under construction


FSRU projects - operational

# Country Location Project name In operation Developer Unit provider

1 UK Teesport, Tees ide Tees ide GasPort 2007 Excelerate Energy Excelerate Energy

2 Argentina Bahia Blanca, 600km SW Buenos Aires Bahia Blanca GasPort 2008 YPF/Repsol/Stream Excelerate Energy

3 USA Massachusetts Bay Northeast Gateway 2008 Excelerate Energy Excelerate Energy

4 Brazi l Rio de Janeiro Baia de Guanabara, VT1 2009 Petrobras Golar LNG

5 Brazi l Ceara Pecem, VT2 2009 Petrobras Golar LNG

6 Kuwait 40km south of Kuwait Ci ty Mina Al -Ahmadi GasPort 2009 KNPC Excelerate Energy

7 Dubai Jebel Al i Dubai LNG 2010 Dusup Golar LNG

8 USA Offshore Gloucester, Massachusetts Neptune Project 2010 GDF Suez GDF Suez

9 Argentina Belen de Escobar, Buenos Aires GNL Escobar 2011 Enarsa/YPF Excelerate Energy

10 Indones ia Jakarta Bay West Java LNG 2012 Pertamina/PGN Golar LNG

FSRU projects - under construction

# Country Location Project name Start up Developer Unit provider

1 Ita ly 20km offshore Livorno OLT Offshore 2012 OLT Offshore LNG Toscana OLT (Golar Frost)

2 Israel Hadera Hadera, Is rea l 2012 Isreal Electric Co Excelerate Energy

3 Indones ia Lampung, Sumatra Lampung FSRU 2013 Perusahaan Gas Negara Höegh LNG

4 China Tianjin Nanjiang Port 2013 CNOOC GDF Suez / Höegh LNG

5 Brazi l Santa Catarina (Guanabara Bay) Sao Francisco, VT3 2014 Petrobras Excelerate Energy

6 Lithuania Kla ipedos Port AB Kla ipedos Nafta 2014 AB Kla ipedos Nafta Höegh LNG

7 Puerto Rico Southern coast of Puerto Rico (near Sa l inas) Aguierre GasPort 2014 Puerto Rico Electric Power Authori ty Excelerate Energy

8 India Kakinada/Vishakapatnam Andhra Pradesh LNG project 2014 APGDC GDF Suez

9 Jamaica Port Esquivel Jamaica LNG, Exmar 2015 Petro Jamaica Exmar

10 Chi le Meji l lones Meji l lones LNG project 2015 Gas Atacama Golar LNG

77

FSRU projects in pipeline to take FID


# Country Location Project name Start up Developer

1 Argentina Puerto Cuatreros , Buenoes Aires Cuatreros 2013 Enarsa/YPF

2 Bangladesh Moheshkhal i Is land, Bangladesh Chittagong LNG project 2013 PetroBangla

3 Bahra in Bahra in Bahra in FSRU Bapco

4 Indones ia Java / Semarang Centra l Java LNG 2014 Pertamina

5 Abu Dhabi Fuja i rah Abu Dhabi LNG project 2014 Government

6 Chi le Quintero Bay Quintero LNG project 2014 Colbun/AES Gener

7 Uruguay 12km off the coast, Sol i s Grande GNL Del Plata 2014 UTE/Ancap

8 India Gangavaram, Andhra Pradesh Petronet floater LNG 2014 Petronet

9 Lebanon Lebanon Lebanon FSRU 2015 Government

FSRU projects - proposed (study)

# Country Location Project name Start up Developer/operator

1 Albania TBC Albania Albania LNG*

2 Argentina 15 mi les southeast of Bahia Blanca Punta Al ta LNG*

3 Argentina Rio Negro San Matias Gul f

4 Bangladesh Bangladesh LNG project Bangladesh Power Development Board

5 Belgium Zeebrugge Zeebrugge second jetty Exmar

6 China Shandong Shandong LNG CNOOC

7 China Yancheng Yancheng LNG CNOOC

8 Chi le Talcahuano Concepcion International

9 Croatia Croatia Adria LNG Pl inacro

10 Germany Wilhelmshaven Wilhelmshaven GasPort Excelerate Energy

11 Ghana Ghana Ghana LNG Ghana Energy Commiss ion

12 Greece Greece Gulf of Corinth

13 Greece Greece Kavala*

14 Guadeloupe Guadeloupe Guadeloupe LNG EDF/Gasfin

15 India West coast Swan Energy

16 India West coast Rel iance Power

17 Ita ly Ita ly Azzurro LNG TORP

18 Ita ly Fa lconara, Le Marche Fa lconara LNG

19 Ita ly Offshore, Le Marche Tri ton LNG Höegh LNG

20 Kenya Kenya Kenya LNG Kenya Electrici ty Generation Co

21 Malays ia Port Dickson, Malays ia Melaka LNG

22 Martinique Martinique Martinique LNG EDF/Gasfin

23 Mexico Tamaul ipas , Puerto Mezquita l , offshore GoM El Dorado

24 Mexico Baja Ca l i fornia Offshore Rosari to

25 Netherlands Ri jn Platform, Offshore Hague TAQA LNG

26 Pakis tan Karachi Mashal LNG* Sui Southern Gas

27 Panama Bahia de las Minas

28 Panama Colon Panama LNG

29 Sri Lanka Sri Lanka Sri Lanka LNG Government

30 United Kingdom East Iri sh Sea, Offshore Morecambe Bay Port Meridian Höegh LNG

31 United Kingdom East Iri sh Sea Gateway LNG

32 Vietnam Vietnam Vietnam LNG*

78

Unconventional gas should not be a threat to LNG demand outside of US

Source: Wood Mackenzie; IEA; Pareto

Europe: Growth in demand and prod ’10-‘25 China: Growth in demand and prod ’10-‘25

Several factors point to fairly low growth in unconventional gas outside of US, including

Lack of (i) detailed data on the geological potential of the resources, (ii) experience with onshore drilling, and (iii) pipeline infrastructure, rigs and fracturing equipment

High population density. Many European countries have a population density above 100-200 hab/km2 compared to 30 hab/km2 in the US and 3 hab/km2 in Canada

Less favorable geology. European shale resources are on average 1.5 times deeper underground than in the US, according to the Oxford Institute for Energy Studies

265

21 50

8.6%

1.3%

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

0

30

60

90

120

150

180

210

240

270

Chinese demand Chinese conventionalprod.

Chineseunconventional prod.

Growth 2010-2025 (lhs) CAGR 2010-2025 (rhs)

Growth 2010-2025 (bcm) CAGR 2010-2025

136

-82

9

1.5%

-2.4%

-3%

-2%

-1%

0%

1%

2%

-100

-75

-50

-25

0

25

50

75

100

125

150

European demand Europeanconventional prod.

Europeanunconventional prod.


Growth 2010-2025 (bcm) CAGR 2010-2025

126 126 126 126 126 126 126 12696

113

119 122 125 128151

174194 205

100

150

200

250

300

350

2009 2010 2011 2012e 2013e 2014e 2015e 2016e 2017e 2018e

Asian LNG supply

Middle East LNG supply, net of domestic demand

Asian LNG demand

bcm

79

Atlantic – Asian trade is likely to increase

*Supply is based current capacity and capacity under construction. Demand is based on regasification capacity additions and IEA forecasts, CAGR of 7% in 2010-2018 Source: BP; IEA; Company data; Pareto

Asian LNG demand vs. Asian and Middle Eastern LNG supply 2009 – 2018e

Potential for Atlantic – Asian flow is higher in 2013-

2018 than in 2011-2012

80

Commodity markets cycle

*2012-2016e based on 92% utilization of existing capacity and capacity under construction **Assumes that 1 bcm/year requires 1.15 ships ***Assumes that 50% of current proposed capacity comes on stream Source: Golar LNG

EMBRYONIC GROWTH MATURE

80

Capital intensive infrastructure projects

Bi-lateral take or pay arrangements

Project financing

Point-to-point long-term contracts

Crude 1970 US crude decline Global trade rises 1983 NYMEX Platts/OPIS indices NA Gas 1987 Take or pay contracts 1987+ FERC 497/636 Gas Marketers 1990 NYMEX Gas Daily Indices NA Power 1995 Utilities 1995 Mega NOPR Energy merchants 1998 Cal ISO Financial markets LMP LNG Today

Deep physical liquidity

Value chain fragmented

Arbitrage opportunities

Term forward liquidity

Complex derivative/option structure

Numerous firms “rationalized”

Asset, utility, monopoly

players

Merchant optimizers

Active spot trading

Spreads compressing

Forward market tenor

Contract unbundling

Inefficiencies = trading profits

Competition intensifies though capital inflows/new entrants

Spot trading initiated

Poor liquidity

Wide bid/offers

No forward market

Bundled contracts/value chain

Rise of trading firms Time

Commodity Trading

Life-Cycle Patterns

81

The number of trade routes has surged

Source: BP; Pareto

Number of trade routes (Country level)

The number of trade routes have increased from 41 in 2000 to 185 in 2010

41 44 48 43 4856

7284

98

134

163

180

0

25

50

75

100

125

150

175

200

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Number of routes (country level)

82

Imports and exports of spot and short term volumes 2010

*Defined as contracts with duration of four years or less Source: Bloomberg; IEA; Pareto

Spot/short term* imports 2010

Country bcm Share

1 Europe 18.4 33%

2 Japan 9.8 17%

3 Korea 7.5 13%

4 US 4.0 7%

5 Taiwan 3.5 6%

6 Middle East 2.9 5%

7 Brazil 2.9 5%

8 India 2.2 4%

9 Argentina 1.8 3%

10 China 1.5 3%

11 Canada 0.9 2%

12 Chile 0.4 1%

13 Mexico 0.3 1%

14 Puerto 0.1 0%

Spot/short term* exports 2010

Country bcm Share

1 Qatar 14.4 26%

2 Trinidad & Tobago 9.6 17%

3 Nigeria 6.9 12%

4 Egypt 4.1 7%

5 Russia 4.1 7%

6 Norway 2.7 5%

7 Oman 2.2 4%

8 Yemen 2.1 4%

9 Australia 1.7 3%

10 Equat. Guinea 1.7 3%

11 Algeria 1.6 3%

12 Abu Dhabi 1.3 2%

13 Malaysia 1.3 2%

14 Peru 0.9 2%

15 US 0.8 1%

16 Indonesia 0.6 1%

83

Underlying sources of spot LNG volumes

Ramp-up volumes: Liquefaction plants in the ramp-up phase whose long term contracts not yet have taken effect have available LNG volumes for the spot market

Liquefaction capacity deliberately set aside for spot sale: Increased liquidity in spot gas markets in Europe and US has given confidence to LNG producers that they will be able to market volumes not covered by long-term contracts

Self contracting: In many cases E&P companies has self-contracted LNG volumes, which their trading arms sell in the spot market to capture arbitrage opportunities

Diverted cargoes: LNG volume on long term contracts might be diverted away from its original destination and sold spot. In this case, the extra profit earned by diverting the cargo is shared between the seller and the original buyer

Reloaded LNG cargoes: Once a LNG cargo has been delivered at the original buyer’s terminal it can be shipped further to a new buyer. In this case the original buyer keeps all the profit.

Source: Pareto

84

LNG fleet ownership profile

Independent shipping companies own around 27% of the current operational fleet and have 10% of the orders

National companies own 63% of the fleet and have 80% of the orders

Multinational oil and gas companies - notably Shell, BG and BP - have 11% of the fleet and 10% of the orders

*As at 1 March 2011. Ships are assigned to a category based on the majority shareholder. In reality, many ships have a mix of owners that fall across more than one category Source: Wood Mackenzie; Pareto

LNG fleet ownership* profile

11% 10%

27%

52%6%

30%

29%

27%10%

0%

20%

40%

60%

80%

100%

Operational Ordered

Independent National - Other National - South Korea

LNG fleet ownership* profile

85

LNG fleet charterer profile

See next slide for descriptions

*As at 1 March 2011 Source: Wood Mackenzie; Pareto

LNG fleet charterer* profile

17% 15%

12% 14%

20%29%

53%43%

0%

20%

40%

60%

80%

100%

Operational Ordered

LNG seller controlled Multinational Independent LNG buyer controlled

LNG fleet charterer profile

86

LNG fleet charterer categories

LNG seller controlled: Mostly national LNG exporters, including Nigeria LNG, Oman LNG, Petronas, Qalhat LNG, Qatargas, RasGas and Sonatrach. In most instances, ships are chartered in from national shipping companies, or joint ventures where local entities have stakes in ships e.g. Qatar Gas Transport.

Multinational controlled: Multinational oil and gas companies, such as Shell, BP, GDF Suez and BG, are now active charterers of independently-owned ships

Buyer controlled: A ship employed by a company that's main activity in LNG is as a buyer (will be on the buy side of long-term contracts, focus of LNG assets will be on the regas side. Examples include TEPCO, Tokyo Gas and KOGAS.

Independent controlled: A ship employed by a company that does not have significant LNG assets (apart from ships). Could be a shipowner or a trader. These companies have ordered ships often without commitment to charters. Some of these owners seek to deploy their ships in short and medium-term contracts where freight rates could potentially be substantially higher than those obtainable under long-term contracts

Source: Pareto

87

World LNG exports and imports 2000 - 2011

Source: Bloomberg; Pareto

World LNG exports 2000 - 2011

World LNG imports 2000 - 2011 World LNG imports distribution 2010

World LNG exports distribution 2010

0

40

80

120

160

200

240

280

320

360


Atlantic basin Africa Middle East Asia/Pacific

World LNG exports (bcm, annualized)

39 %

34 %

20 %

7 %

Asia/Pacific

Middle East

Africa

Atlantic (ex.Africa)

World LNG exports by region 2010

0

40

80

120

160

200

240

280

320

360


Latin America North America Europe Asia

World LNG imports (bcm, annualized)

58 %28 %

7 %

3 % 4 %

Asia

Europe

North America

Latin America

Other

World imports by region 2010

88

Global LNG imports and exports by country

Source: BP; Pareto

bcm ShareJapan 93.5 31%South Korea 44.4 15%Spain 27.5 9%United Kingdom 18.7 6%Taiwan 14.9 5%France 13.9 5%China 12.8 4%US 12.2 4%India 12.2 4%Italy 9.1 3%Turkey 7.9 3%Belgium 6.4 2%Mexico 5.7 2%Chile 3.1 1%Portugal 3.0 1%Brazil 2.8 1%Kuwait 2.8 1%Canada 2.0 1%Argentina 1.8 1%Greece 1.2 0%Dominican Republic 0.8 0%Puerto Rico 0.8 0%UAE 0.2 0%

Total 297.6 1.0

Global LNG imports 2010

bcm ShareQatar 75.7 25%Indonesia 31.4 11%Malaysia 30.5 10%Australia 25.4 9%Nigeria 23.9 8%Trinidad & Tobago 20.4 7%Algeria 19.3 6%Russia 13.4 5%Oman 11.5 4%Egypt 9.7 3%Brunei 8.8 3%UAE 7.9 3%Yemen 5.5 2%Norway 5.3 2%Equatorial Guinea 5.2 2%Peru 1.8 1%US 1.6 1%Libya 0.3 0%Angola 0.0 0%Total 297.6 100%

Global LNG exports 2010

89

World LNG demand to grow rapidly, led by Non-OECD Asia and Europe

Growth 2010-2025e

Non-OECD Asia

CAGR: 10.6%

39% of world growth

Europe

CAGR: 5.4%

38% of world growth

OECD Asia

CAGR: 1.3%

10% of world growth

Other (Latin Am, Africa)

CAGR: 4.6%

13% of world growth

Source: BP; Pareto

World LNG demand 1990 – 2025e

0

100

200

300

400

500

600

700

1990 1995 2000 2005 2010 2015 2020 2025 2030

Other Non-OECD Asia OECD Asia Europe

World LNG imports (bcm/year)

90

There is large upside to gas demand

Gas consumption per capita is significantly lower than oil consumption per capita across the board

Source: BP; IMF; Pareto

Consumption per capita: Natural gas vs. oil

13.9

6.1

2.9

0.7 0.4 0.3

22.2

10.3

4.5 4.6

2.41.0

0

5

10

15

20

25

US EU World Brazil China India

Natural gas Oil

boe/year

91

Power generation is the main demand driver

Power generation is expected to be the main growth driver for natural gas demand, though firm growth is also expected in the industrial and residential/commercial segments

Natural gas has several advantages compared to other fuels in the power generation segment:

Cheap, Clean, Low technical risk, Short lead times, Generation flexibility, Storable

Source: Exxon; IEA; Pareto

World gas demand growth ‘10-’30 (Exxon) World gas demand growth ‘10-’30 (IEA)

2.3%

1.7%

1.4%

1.9%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

0

300

600

900

1,200

1,500

Power Ind./Other Residential/Com. Total


bcm CAGR 2010-2030

1.6%1.5%

0.9%

1.4%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

0

300

600

900

1,200

1,500

Power Ind./Other Residential/Com. Total


bcm CAGR 2008-2030

92

Gas is taking a larger share of the power generation market

Natural gas is taking a lager share of the power generation market

1980: 17%

2010: 24%

2030e: 27%

Key drivers: Natural gas is

Cheap

Clean

Low technical risk

Short lead times

Generation flexibility

Storable

Source: Exxon; Pareto

World power generation distribution 1980 – 2030e

22%13% 8% 7% 5% 4% 3%

17%20%

21% 22% 24% 26% 27%

44%41% 43% 45% 47% 42% 37%

9%18% 19% 17% 15% 17% 19%

8% 6% 6% 6% 6% 6% 6%

0%

20%

40%

60%

80%

100%

1980 1990 2000 2005 2010 2020e 2030e

Other Renewables Wind Hydro Nuclear Coal Gas Oil

World power generation demand distribution

93

Gas is cleaner than other fossil fuels and more efficient than electricity

Gas is by far the cleanest fossil fuel Gas is much more energy efficient than electricity

Source: EIA; AGA; Pareto

CO2 emissions by fuel Energy efficiency

118

140156

173

195215

0

50

100

150

200

250

Natural gas Propane Gasoline Residual oil Wood Coal

CO2 emissions by fuel (pounds CO2/mmbtu)

370

110

0

100

200

300

400

Electricity Natural gas

Energy needed to deliver 100 mmbtu to end-users (mmbtu)

94

Gas is a cheap source of new power, which is supportive for demand

At USD 12-14/mmbtu gas is competitive relative to other energy sources, such as coal, nuclear and renewables, when it comes to investments in new power generation capacity

*Levelised cost includes all the costs over the power plant’s lifetime: initial investment, operations and maintenance, cost of fuel, and cost of capital . Assumptions: Carbon price at USD 30/ton, coal price at USD 134/ton and gas price at USD 13/mmbtu Source: IEA; Pareto

Levelised* cost of electricity for various fuel sources

0

50

100

150

200

250

300

350

Gas Coal Coal (CCS) Nuclear Windonshore

Solar PV(current)

Solar PV(2013e)

Capital Operational Fuel CO2

LCOE (USD/MWh)

95

Japanese nuclear-to-LNG switching sensitivity

Source: IEA; Pareto

Japanese nuclear-to-LNG swithing sensitivity

5 11 1621

2632

3742

4753

2%4%

5%7%

9%11%

12%14%

16%18%

0 %

4 %

8 %

12 %

16 %

20 %

0

10

20

30

40

50

60

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Share of nuclear power 2010 replaced by gas

Increased Japanese LNG demand (lhs)

Increased Japanese LNG demand relative to world LNG demand (rhs)

bcm vs. world LNG demand 2010

96

German nuclear-to-gas switching sensitivity

Source: IEA; Pareto

German nuclear-to-gas swithing sensitivity

3 68

1114

1720

2225

28

3%6%

10%13%

16%19%

22%25%

29%32%

0 %

5 %

10 %

15 %

20 %

25 %

30 %

35 %

0

5

10

15

20

25

30

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Share of 2010 nuclear power replaced by gas

Increased German gas demand (lhs)

Increased German gas demand relative to European LNG demand (rhs)

bcm vs. European LNG demand 2010

97

Nuclear power growth could come in well below consensus forecasts…

Over 2008-2030 world nuclear capacity declines from 391 GW to

340 GW in scenario A, 44% below IEA’s base case forecast (602 GW)

139 GW in scenario B, 47% below IEA’s base case forecast (602 GW)

*Assumption: All nuclear capacity that currently is under construction is brought online, but no additional capacity is added. In scenario A, plants are shut down after 50 years, while they are shut down after 40 years in in scenario B Source: IEA; Pareto

Scenario A*: Nuclear capacity 2008 vs. 2030 Scenario B*: Nuclear capacity 2008 vs. 2030

391

68119

340

-44%

IEA base case

0

100

200

300

400

500

600

700

2008 Underconstruction

Shutdown (>50years)

2030

World nuclear capacity, GW

391

68

320

139

-77%

IEA base case

0

100

200

300

400

500

600

700

2008 Underconstruction

Shutdown (>40years)

2030

World nuclear capacity, GW

98

… which gives considerable upside risk to consensus gas demand forecasts

Under scenario A and B, world gas demand increases by 2.0% and 2.4% p.a. through 2030, both significantly above IEA’s base case forecast of 1.5%

In 2030, world gas demand stands at 4,487 bcm in scenario A and 4,836 bcm in scenario B, or about 12% and 20% higher than IEA’s base case forecast of 4,021 bcm

Source: IEA; Pareto

World gas demand 1990 – 2030 under three scenarios

2.0% CAGR

2.4% CAGR

1.5% CAGR

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

1990 1995 2000 2005 2010 2015 2020 2025 2030

1990-2010 IEA base case Scenario A Scenario B

World gas demand (bcm/year(

99

There is upside risk to consensus forecasts for Chinese demand growth

Only 4% of Chinese energy demand is met by gas, significantly lower than in most other countries

By 2020 however, the Chinese government target gas’ share to increase to 10%...

… in which case Chinese gas demand should increase by at least 12% p.a., significantly faster than consensus 4-9% forecast

Source: BP; Pareto

Gas’ share of energy demand by country 2009

55%51%

47%

28% 26% 26% 23% 22%17%

13% 11% 10%

4%

World

0%

10%

20%

30%

40%

50%

60%

Ru

s

Ma

lays

ia

Mid

dle

Eas

t

N. A

m

Ind

on

esi

a

EU

Afr

ica

Lati

n A

m

Jap

an

Sou

th K

ore

a

Asi

a P

aci

fic

Ind

ia

Ch

ina

Natural gas' share of total energy demand

100

LNG supply and demand overview

*Based on 92% utilization Source: Company data; IEA; Pareto

LNG supply and demand overview 2010 2011 2012e 2013e 2014e 2015e 2016e

LNG supply*

Operational & under construction bcm/year 298 331 339 344 348 377 402

Growth y/y - 22.8% 11.0% 2.4% 1.5% 1.1% 8.6% 6.6%

inc. 50% of proposed bcm/year 298 331 339 344 348 378 413

Growth y/y - 22.8% 11.0% 2.4% 1.5% 1.1% 8.8% 9.0%

LNG demand

5.0% annual growth bcm/year 298 331 347 365 383 402 422

7.0% annual growth " 298 331 354 379 405 434 464

Surplus/deficit w/5% demand growth

Operational & under construction " 0 -9 -21 -35 -25 -20

50% of proposed " 0 -9 -21 -35 -24 -10

Surplus/deficit w/7% demand growth

Operational & under construction " 0 0 -15 -35 -58 -56 -62

50% of proposed " 0 0 -15 -35 -58 -55 -51

101

Regasification capacity utilization 2010

Except China, most countries that currently import LNG are fairly well supplied with regasification capacity

Source: IEA; Bloomberg; Pareto

Utilization of regasification capacity 2010

0% 20% 40% 60% 80% 100%

BelgiumUS

GreeceKoreaIndiaBrazilJapan

TaiwanAsia

EuropePortugal

SpainTurkeyFranceChina

Annual average At peak month

Utilization of regasification capacity 2010

102

Overview of regasification capacity 2005 - 2013e

Source: TRI-ZEN; Pareto

World LNG regasification capacity 2005-2013e Utilization of regasification capacity

0

200

400

600

800

1,000

1,200

2005 2006 2007 2008 2009 2010 2011e 2012e 2013e

Asia Europe North America Latin America Middle East

World regasification capacity (bcm/year)

0 %

10 %

20 %

30 %

40 %

50 %

60 %

2005 2006 2007 2008 2009 2010 2011e 2012e 2013e

Asia Europe North America

Utilization of regasification capacity (annual avg)

103

There are healthy profit margins for LNG exports

*Excess profit. Typically captured in the upstream/liquefaction part of the value chain Source: Bloomberg; IEA; Pareto

Qatar – W. Europe at spot gas price

Qatar – Japan/Korea Australia – Japan/Korea

Qatar – W. Europe at Long Term contracts

1.0

4.0

1.9

0.4

2.7

10.0

0

2

4

6

8

10

12

Gas cost Liquefaction Shipping Regas Profit* Gas salesprice (spot

price)

LNG value chain Qatar - W. Europe (USD/mmbtu)

1.0

4.0

1.90.4

5.7

13.0

0

2

4

6

8

10

12

14

Gas cost Liquefaction Shipping Regas Profit* Gas salesprice (Oil-

linked LT)

LNG value chain Qatar - W. Europe (USD/mmbtu)

1.0

4.0

2.00.4

9.1

16.5

0

2

4

6

8

10

12

14

16

18

Gas cost Liquefaction Shipping Regas Profit* Gas salesprice

LNG value chain Qatar - Japan/Korea (USD/mmbtu)

5.0

4.0

1.30.4

5.9

16.5

0

2

4

6

8

10

12

14

16

18

Gas cost Liquefaction Shipping Regas Profit* Gas salesprice

LNG value chain Australia - Japan/Korea (USD/mmbtu)

104

LNG shipping costs overview, July 2012

Source: Bloomberg; Pareto

LNG shipping costs, July 2012

Route USD/mmbtu

Australia to Belgium 3.2

Australia to Japan 1.4

Australia to South Korea 1.4

Australia to Spain 2.8

Australia to United Kingdom 3.2

Australia to US East Coast 3.3

Australia to US Gulf Coast 3.5

Nigeria to Belgium 1.4

Nigeria to Japan 3.8

Nigeria to South Korea 3.6

Nigeria to Spain 1.3

Nigeria to United Kingdom 1.4

Nigeria to US East Coast 1.5

Nigeria to US Gulf Coast 1.7

Qatar to Belgium 2.3

Qatar to Japan 2.3

Qatar to South Korea 2.2

Qatar to Spain 1.9

Qatar to United Kingdom 2.3

Qatar to US East Coast 2.6

Qatar to US Gulf Coast 3.0

Trinidad to Belgium 1.3

Trinidad to Japan 4.8

Trinidad to South Korea 4.7

Trinidad to Spain 1.3

Trinidad to United Kingdom 1.3

105

LNG supply cost estimates

Source: BP; Pareto

Route Gas cost Liquefac. Shipping Regas Total

Australia

Japan 3.0 - 7.0 3.0 - 5.0 1.0 0.5 7.5 - 13.5

US Gulf to

Europe 4.0 3.6 1.0 0.5 9.1

Japan 4.0 3.6 3.0 0.5 11.1

ME to

Europe 0 - 6.0 3.0 - 5.0 1.8 0.5 5.3 - 13.3

Japan 0 - 6.0 3.0 - 5.0 1.9 0.5 5.4 - 13.4

W. Africa

Europe 0 - 6.0 3.0 - 5.0 1.0 0.5 4.5 - 12.5

Japan 0 - 6.0 3.0 - 5.0 2.6 0.5 6.1 - 14.1

E. Africa

Japan 0 - 6.0 3.0 - 5.0 1.5 0.5 5.0 - 13.0

LNG supply cost (USD/mmbtu)

106

LNG supply costs

*Upstream costs range from USD 2/mmbtu to USD 9/mmbtu, liquefaction costs range from USD 3/mmbtu to USD 5/mmbtu, shipping costs range from USD 0.6/mmbtu to USD 3.0/mmbtu Source: Wood Mackenzie; Pareto

LNG supply costs*

7.58.8

10.2 10.6 11.4 12.2

9.310.5 10.5 11.1 11.8

0

2

4

6

8

10

12

14

Pre

lud

e

Go

rgo

n

Ich

thy

s

QC

LNG

Wh

eat

sto

ne

Sab

ine

AP

LN

G

Bro

wse

Plu

to

Kit

ima

t

GLN

G

Cost of LNG supply (USD/mmtbu, shipping to Asia)

FID taken Pre-FID

107

Approximate conversion factors

Source: BP

To

billion cubic billion cubic million tonnes million tonnes trillion British million barrels

Natural gas and LNG metres NG feet NG oil equivalent LNG thermal units oil equivalent

From

1 billion cubic metres NG 1 35.3 0.90 0.74 35.7 6.60

1 billion cubic feet NG 0.028 1 0.025 0.021 1.01 0.19

1 million tonnes oil equivalent 1.11 39.2 1 0.82 39.7 7.33

1 million tonnes LNG 1.36 48.0 1.22 1 48.6 8.97

1 trillion British thermal units 0.028 0.99 0.025 0.021 1 0.18

1 million barrels oil equivalent 0.15 5.35 0.14 0.11 5.41 1

Multiply by

108

Pipes or LNG – the next phase of the Snøhvit project

Today, the gas on the Snøhvit and Albatross fields are transported to the liquefaction plant located in Hammerfest by a 143 km pipeline

The capacity of the plant is about 5.6 bcm/year on one train

With the current solution, the field can produce gas until 2050, but operators want to increase output

Two solutions have been set out:

An extension of current pipes from the Norwegian Sea to the Barents Sea

A second LNG train at Melkøya

Final decision expected in June

The Snøhvit, Albratross and Askeladden gas fields

109

A second train should be less complication than train 1

Constructing a train 2 should be less complicated than train 1:

Operators have learned from the mistakes on train 1, i.e. more experience

Part of the infrastructure is in place

Different parts of the production line can be used both for train 1 and train 2

Likely location of train 2 marked in black circle

Overview picture of the Snøhvit liquefaction plant at Melkøya

110

Disclaimer and legal disclosures

Origin of the publication or report This publication or report originates from Pareto Securities AS (“Pareto Securities”, reg. no. 956 632 374 (Norway) and Pareto Öhman AB (“Pareto Öhman”), reg. no. 556206-8956 (Sweden) and (together the Group Companies or the “Pareto Securities Group”) acting through their common unit Pareto Securities Research. The Group Companies are supervised by the Financial Supervisory Authority of their respective home countries. Content of the publication or report This publication or report has been prepared solely by Pareto Securities Research. Opinions or suggestions from Pareto Securities Research may deviate from recommendations or opinions presented by other departments or companies in the Pareto Securities Group. The reason may typically be the result of differing time horizons, methodologies, contexts or other factors. Basis and methods for assessment Opinions and price targets are based on one or more methods of valuation, for instance cash flow analysis, use of multiples, behavioral technical analyses of underlying market movements in combination with considerations of the market situation and the time horizon. Key assumptions of forecasts, price targets and projections in research cited or reproduced appear in the research material from the named sources. The date of publication appears from the research material cited or reproduced. Opinions and estimates may be updated in subsequent versions of the publication or report, provided that the relevant company/issuer is treated anew in such later versions of the publication or report. Credit ratings are based on the same rating scale as international rating agencies and represent the opinion of Pareto Securities Research as to the relative creditworthiness of securities. A credit rating on a standalone basis should not be used as a basis for investment operations. Pareto Securities Research may also provide credit research with more specific price targets based on different valuation methods, including the analysis of key credit ratios and other factors describing the securities creditworthiness, peer group analysis of securities with similar creditworthiness and different DCF-valuations. All credit ratings mentioned in this publication or report are Pareto Securities Research’s own credit rating estimates unless otherwise mentioned. All descriptions of loan agreement structures and loan agreement features are obtained from sources which Pareto Securities Research believes to be reliable, but Pareto Securities Research does not represent or warrant their accuracy. Be aware that investors should go through the specific complete loan agreement before investing in any bonds and not base an investment decision based solely on information contained in this publication or report. Pareto Securities Research has no fixed schedule for updating publications or reports. Unless otherwise stated on the first page, the publication or report has not been reviewed by the issuer before dissemination. In instances where all or part of a report is presented to the issuer prior to publication, the purpose is to ensure that facts are correct. Validity of the publication or report All opinions and estimates in this publication or report are, regardless of source, given in good faith and may only be valid as of the stated date of this publication or report and are subject to change without notice. No individual investment or tax advice The publication or report is intended only to provide general and preliminary information to investors and shall not be construed as the basis for any investment decision. This publication or report has been prepared by Pareto Securities Research as general information for private use of investors to whom the publication or report has been distributed, but it is not intended as a personal recommendation of particular financial instruments or strategies and thus it does not provide individually tailored investment advice, and does not take into account the individual investor’s particular financial situation, existing holdings or liabilities, investment knowledge and experience, investment objective and horizon or risk profile and preferences. The investor must particularly ensure the suitability of an investment as regards his/her financial and fiscal situation and investment objectives. The investor bears the risk of losses in connection with an investment. Before acting on any information in this publication or report, we recommend consulting your financial advisor. The information contained in this publication or report does not constitute advice on the tax consequences of making any particular investment decision. Each investor shall make his/her own appraisal of the tax and other financial merits of his/her investment.

V. 08.12

111

Disclaimers and disclosures

Sources This publication or report may be based on or contain information, such as opinions, recommendations, estimates, price targets and valuations which emanate from Pareto Securities Research’ analysts or representatives, publicly available information, information from other units or companies in the Group Companies, or other named sources. To the extent this publication or report is based on or contains information emanating from other sources (“Other Sources”) than Pareto Securities Research (“External Information”), Pareto Securities Research has deemed the Other Sources to be reliable but neither the companies in the Pareto Securities Group, others associated or affiliated with said companies nor any other person, guarantee the accuracy, adequacy or completeness of the External Information. Ratings Equity ratings: “Buy” Pareto Securities Research expects this financial instrument’s total return to exceed 10% over the next six months “Hold” Pareto Securities Research expects this financial instrument’s total return to be 0-10% over the next six months “Sell” Pareto Securities Research expects this financial instrument’s total return to be negative over the next six months Rating system used by Pareto Öhman AB prior to 16 September 2011: “Outperform” The stock is expected to outperform the return on Pareto Öhman’s Nordic sector universe in six to twelve months “Neutral” The stock is expected to perform in line with the return on Pareto Öhman’s Nordic sector universe in six to twelve months “Underperform” The stock is expected to underperform the return on Pareto Öhman’s Nordic sector universe in six to twelve months Credit ratings: AAA Best Quality AA+ / AA / AA- Strong ability for timely payments A+ / A / A- Somewhat more exposed for negative changes BBB+ / BBB / BBB- Adequate ability to meet payments. Some elements of protection. BB+ / BB / BB- Speculative risk. Future not well secured B+ / B / B- Timely payments at the moment, but very exposed to any negative changes CCC+ /CCC/ CCC- Default a likely option Limitation of liability Pareto Securities Group or other associated and affiliated companies assume no liability as regards to any investment, divestment or retention decision taken by the investor on the basis of this publication or report. In no event will entities of the Pareto Securities Group or other associated and affiliated companies be liable for direct, indirect or incidental, special or consequential damages resulting from the information in this publication or report. Neither the information nor any opinion which may be expressed herein constitutes a solicitation by Pareto Securities Research of purchase or sale of any securities nor does it constitute a solicitation to any person in any jurisdiction where solicitation would be unlawful. All information contained in this research report has been compiled from sources believed to be reliable. However, no representation or warranty, express or implied, is made with respect to the completeness or accuracy of its contents, and it is not to be relied upon as authoritative. Risk information The risk of investing in certain financial instruments, including those mentioned in this document, is generally high, as their market value is exposed to a lot of different factors such as the operational and financial conditions of the relevant company, growth prospects, change in interest rates, the economic and political environment, foreign exchange rates, shifts in market sentiments etc. Where an investment or security is denominated in a different currency to the investor’s currency of reference, changes in rates of exchange may have an adverse effect on the value, price or income of or from that investment to the investor. Past performance is not a guide to future performance. Estimates of future performance are based on assumptions that may not be realized. When investing in individual shares, the investor may lose all or part of the investments.

112


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113


Distribution in Singapore Pareto Securities Asia Pte Ltd (“Pareto Securities Asia”) is an exempt financial advisor under the Singapore Financial Advisers Act and a subsidiary of Pareto Securities AS in Singapore. This report is directed only to "accredited investors", "expert investors" and "institutional investors" as defined in the Singapore Securities and Futures Act. This report is intended for general circulation amongst such investors and does not take into account the specific investment objectives, financial situation or particular needs of any particular person. You should seek advice from a financial adviser regarding the suitability of any product referred to in this report, taking into account your specific financial objectives, financial situation or particular needs before making a commitment to purchase any such product. Please contact Pareto Securities Asia, 16 Collyer Quay, # 27-02 Hitachi Tower, Singapore 049318, at +65 6408 9800 in respect of any matters arising from or in connection with this report. Copyright This publication or report may not be mechanically duplicated, photocopied or otherwise reproduced, in full or in part, under applicable copyright laws. Any infringement of Pareto Securities Research´s copyright can be pursued legally whereby the infringer will be held liable for any and all losses and expenses incurred by the infringement.

114


Appendix B

Disclosure requirements pursuant to the Norwegian Securities Trading ST Regulation § 3-11, letters d-f, ref the Securities Trading Act Section 3-10

Overview over issuers of financial instruments where Pareto Securities AS have prepared or distributed investment recommendation, where Pareto Securities AS or related companies have been lead manager/co-lead manager or have rendered publicly known not immaterial investment banking services over the previous 12 months:

Appendix C

Disclosure requirements pursuant to the Norwegian Securities Trading ST Regulation § 3-11 (4)

Column I shows the overall ratio of “Buy”, “Hold” and “Sell” in Pareto’s Recommendations in financial instruments.

Column II shows the ratio of “Buy”, “Hold” and “Sell” in Pareto’s Recommendations in financial instruments where Pareto Have provided investment banking services to the issuer the previous 12 months.

Appendix A

Disclosure requirements pursuant to the Norwegian Securities Trading Regulations section 3-10 (2) and section 3-11 (1), letters a-b

Pareto Securities AS does not alone or - together with affiliated companies or persons – owns a portion of the shares exceeding 5 % of the total share capital in any company where a recommendation has been produced or distributed by Pareto Securities AS.

Pareto Securities AS may hold financial instruments in companies where a recommendation has been produced or distributed by Pareto Securities AS in connection with rendering investment services, including Market Making.

Please find below an overview of material interests in shares held by employees in Pareto Securities AS, in companies where a recommendation has been produced or distributed by Pareto Securities AS.

By material interest is meant holdings exceeding a value of NOK 50 000.

Column I Column II

Buy 63.2% 94.4%

Hold 28.2% 5.6%

Sell 8.6% 0.0%

This overview is updated quarterly (last updated 15.07.2012).

CompanyAnalyst

holdings

Total

holdingsCompany

Analyst

holdings

Total

holdings

Algeta - 1 000 Olav Thon Eiendomsselskap 420 938

Archer - 17 500 Orkla - 194 202

Bonheur - 11 800 Petroleum Geo-Services - 35 600

BW Offshore - 230 486 Polarcus Limited - 280 612

BWG Homes 18 000 18 210 Protector Forsikring - 499 000

Cermaq - 3 000 Questerre Energy - 277 206

Discovery Offshore - 12 000 Renewable Energy Corp. - 24 961

DNB - 116 700 S.D. Standard Drilling - 100 000

DOF - 30 000 SalMar - 58 400

EOC Limited - 25 000 Sandnes Sparebank - 6 295

Farstad Shipping - 21 700 Seadrill - 4 550

Fred Olsen Energy 100 300 Selvaag Bolig - 50 000

Frontline - 10 000 Ship Finance Ltd - 2 768

Gjensidige Forsikring - 99 427 Solstad Offshore - 4 100

Golden Ocean Group - 50 380 Songa Offshore - 4 000

Havila Shipping - 12 450 Sparebank 1 Nord-Norge - 20 637

Höegh LNG - 86 203 Sparebank 1 SR-Bank - 129 128

Itera 40 000 41 000 Sparebanken Øst - 22 349

Kongsberg Gruppen - 73 700 Spectrum - 197 000

Lerøy Seafood Group - 37 400 Statoil - 58 550

Marine Harvest Group - 50 000 Storebrand - 2 263

Morpol - 116 214 Subsea 7 - 75 406

Norsk Hydro - 461 773 Telenor - 57 200

Norske Skogindustrier - 37 496 TGS-NOPEC - 7 450

Northland Resources - 392 000 Veidekke - 42 400

Norwegian Air Shuttle - 500 Wilh. Wilhelmsen Holding A - 404

Noreco - 245 807 Yara International - 31 328

Odfjell - 7 300

This overview is updated monthly (last updated 31.07.2012)

- Aker - GasLog - Prosafe

- Aker Floating Production - Haikui - Protector Forsikring

- Aker Seafoods - Havila Shipping - Reservoir Exploration Technology

- American Shipping Company - Hercules Offshore - Rocksource

- Archer - Houston American Energy Corp - SalMar

- Austevoll Seafood - Höegh LNG - Scana Industrier

- Bergen Group - Idex - Seadrill

- BW Offshore - Interoil - Selvaag Bolig

- Camillo Eitzen & Co. - KrisEnergy Holding Company - Sevan Marine

- Clearwater - Lyse Energi - Shamaran Petroleum

- Codfarmers - Marine Aluminium Holding - Siemens

- Concedo - Marine Subsea - SinOceanic

- DDI - Mecom Group - Songa Offshore

- Det Norske Oljeselskap - Neptune Offshore - Sparebank 1 SR Bank

- DNO International - Noreco - Sparebanken Møre

- Dockwise - Norse Energy Corp - Sparebanken Øst

- DOF - North Atlantic Drilling - Statoil

- Dolphin Group - North Energy - Swedbank

- Eitzen Maritime - Northland Resources - Teekay LNG

- Electromagnetic Geoservices - OSX - TTS Group

- Equinox Offshore - Pacific Drilling - Voss Resort

- Expro Intl. Group Holding - Polarcus - Wilh. Wilhelmsen

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Appendix D

This part applies to research reports prepared by Pareto Öhman. Disclosure of positions in financial instruments The beneficial holding of the Pareto Group is 1% or more of the total share capital of the following companies included in Pareto Öhman’s research coverage universe: Isconova, and Ruric. The Pareto Group has material holdings of other financial instruments than shares issued by the following companies included in Pareto Öhman’s research coverage universe: RusForest and PA Resources. Disclosure of assignments and mandates During the past 12 months, members of the Pareto Group have been lead manager or co-lead manager of publicly disclosed issues or offers of or with regard to securities of the following companies included in Öhman’s research coverage universe: Shamaran Petroleum, Lucara Diamonds, Tinkoff/Edigaco and Trigon Agri. During the past 12 months, members of the Pareto Group have provided other investment banking services to and received compensation for such services from the following companies included in Öhman’s research coverage universe: Africa Oil, BlackPearl Resources, Isconova, JLT Mobile Computers, RusForest, Trigon Agri, Lucara Diamonds and Shamaran Petroleum. Members of the Pareto Group provide market making or other liquidity providing services to the following companies included in Öhman’s research coverage universe: 2Entertain, Africa Oil, Beijer Electronics, Black Pearl Resources, Cloetta, Coastal Contacts, Episurf, Fastighets AB Balder, G&L Beijer, Isconova, JLT, NAXS, Partnertech, Prevas, Ruric, Shamaran Petroleum, Tethys Oil and Trigon Agri. Members of the Pareto Group have entered into agreements concerning the inclusion of the company in question in Öhman’s research coverage universe with the following companies: Africa Oil, Isconova and Shamaran Petroleum. This overview is updated monthly. Previous rating system (up to 16 Sep 2011) Rating Expected total return in six to twelve months OUTPERFORM The stock is expected to outperform the return on our Nordic sector universe NEUTRAL The stock is expected to perform in line with the return on our Nordic sector universe UNDERPERFORM The stock is expected to underperform the return on our Nordic sector universe

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