Gilmore Maran Gas LNG Market Outlook

MARAN GAS MARITIME Inc.

•1

MARAN GAS MARITIME INC

The Perfect Balance of Efficiency and Reliability

Athens ~ June 7, 2011

LNG Market OutlookBy: Richard Gilmore

SIAM CONFERNECE

MARAN GAS MARITIME Inc.

ANGELICOUSSIS SHIPPING GROUP THE FLEET: NO

Operating 32

On Order 16

Sub-Total 48

Operating* 36

On Order 4

Bareboat out 7

Sub-Total 49

Operating 7

On Order 3 LNG/C

Sub-Total 10

TOTAL 105

•DRY CARGO

• avg. age 8.2 years

•TANKERS


•LNG / LPG


• (897,000 cubic meters)

•Fleet as at April 2011•* 15 Tankers are under Management but owned by 3rd party.

Page 1

MONTH 2009© POTEN & PARTNERSJune 2011 Page 3

LNG Fleet Development

The LNG fleet has expanded rapidly over the last decade – +300% since 2000• The last ten years has seen fleet growth

of 14% (CAGR) but in the next five years growth is expected to slow to ~2% until the end of the decade when growth is expected to increase in support of new projects

• Past growth led by Qatari projects who ordered 45 Q-flex/Q-max vessels between 2004 and 2007 for deliveries between 2007 and 2010

• Ship sizes are not growing over time on a linear basis – current preferences 155,000 – 160,000 cbm

• Propulsion preference has shifted from Steam Turbine to the more efficient D/TFDE systems

• The existing LNG orderbook represents 14% of the overall number of vessels on the water, with 49 vessels on order and 356 currently trading

Historical LNG Fleet Development Historical LNG Fleet Development

0

10

20

30

40

50

60

70

1969 1974 1979 1984 1989 1994 1999 2004 2009 20140

100

200

300

400

500

600

CBM # of Vessels

14% CAGR

9% CAGR

cbm millions # of vessels

2% CAGR

LNG OrderbookLNG OrderbookLNG Fleet by SizeLNG Fleet by Size

0

10

20

30

40

50

60

70

80

90

100

<100 122-129 130-139 140-149 150-157 160-170 171-177 Q-Flex Q-Max

# of vessels

Existing (356) To be Delivered (49)

49

14%

0

10

20

30

40

50

LNG0%

2%

4%

6%

8%

10%

12%

14%

# of ships % of Fleet

Source: Poten & Partners



LNG Demand & Supply

LNG Demand • East of Suez

- Weak industrial demand in major Asian industrial countries (except Japan)- Volatile international commodity prices- Excess volumes being absorbed by Japan, Taiwan, China, India and the

West- Impact of lost Japanese nuclear capacity on LNG markets remains

uncertain, but expect nuclear capacity to remain offline for an extended period

• West of Suez- US unconventional gas supplies are limiting LNG demand- Contracting industrial demand in the US, EU & UK- Price arbitrage between US and Europe determining product deliveries- Availability of storage is a key driver – limited in Europe and Asia

• There is growth, but how best to secure access to it- New markets –Brazil, Argentina, Chile, Middle East- Existing markets – United States, Europe, Asia

LNG Supply• Significant new capacity coming online

- New projects coming on-line include Pluto, PNG, Gorgon, Angola LNG- Gladstone LNG, QCLNG, Donggi Senoro and Prelude have recently taken

FID- Anticipate Wheatstone FID in 2011 and Browse and Pacific LNG FID in

2012- Less certain on West Africa / North Africa project development- A total of 281 MMt/y of LNG supply expected by 2015

• Regionalization of trade is re-emerging with the Middle East acting as the “swing” supplier

• Anticipate tight supply market in 2014 through 2016 as delays effect grassroot developments

• Role and position of Qatar increasing in importance – swing supplier, supplier of last resort, quickest to market

LNG DemandLNG Demand

104 108 110125 132 142

159174 174 183

221242

254266 272 281

0

50

100

150

200

250

300

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Mill

ion

Tons

of L

NG

LNG SupplyLNG Supply

114 119 122 130 137 147166 172 176 184

222243

256 266 272 281

0

50

100

150

200

250

300

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Mill

ion

Tons

of L

NG




New LNG Supply Projections

Growing LNG supplies • Current supplies: ~220 Mmtpa

• Anticipated ~110 Mmtpa of new supplies by 2020 originating from:

- Australia

- Nigeria (NLNG 7 and Brass)

- Angola

- Papua New Guinea

Export projects are experiencing slower growth than originally anticipated at the end of last decade: • Shale gas exploitation

• Global recession contracting industrial demand growth

• Lower than expected gas prices in the west

• Inflationary pressure on input / EPC costs

Over 90 vessels will be needed to cover the ship requirements from new projects by 2020

Incremental Supply from Future LNG Projects and Ship RequirementsIncremental Supply from Future LNG Projects and Ship Requirements

Projection of New LNG Supplies, CumulativeProjection of New LNG Supplies, Cumulative

0

20

40

60

80

100

120

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Mill

ion

Tons

of L

NG

Australia Canada FPSO's Indonesia Papua New Guinea Algeria Angola Egypt Equatorial Guinea Nigeria

0

10

20

30

40

50

60

70

80

90

100

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

Mill

ion

Tons

of L

NG

0

10

20

30

40

50

60

70

Ship

Req

uire

men

ts (1

65,0

00m

3 eq

uiv.

)New LNG Production - Atlantic

New LNG Production - Pacific

Project Ship Requirement




LNG Trade Route Proliferation

• LNG trade has grown by 7% CAGR since 2000

• A short-term LNG market has developed over the last 10 years

2010 Global LNG Trade Routes2010 Global LNG Trade Routes




100%

Short-term Long-term

100%


2%

98%


Via Peru

21%79%




Growth in LNG Ships/Terminals/Projects

Year Up to 1979

Up to 1989

Up to 1999

Up to Present

LNG Ships

40 60 106 360

Import Terminals

11 23 36 84

Export Terminals

8 16 25 53


Regional Trade Flow Affected by Prevailing Global LNG Market

LNG is priced either by reference to oil or to a gas-on-gas market• Liquidity of gas-on-gas markets

enables the establishment of a market price

• Gas-on-gas markets enable trading and diversions

• JCC linked Asian LNG prices are well above liquid market gas prices in the Atlantic Basin

• Recent loss of power generation in Japan has further increased prices in the Far East

Disparity of gas pricing is expected to continue for some time • Additional LNG demand from Japan

will accelerate the tightening of LNG supply markets

• NBP and Henry Hub prices are likely to remain disconnected

• Bearish outlook on US gas pricing with potential increases coming from the growing re-export trade

• South American demand continues to rise

Price Indexations & Factors affecting Long-Term ContractsPrice Indexations & Factors affecting Long-Term Contracts

Henry Hub

NBPOil Product

JCC

Counter-SeasonalPremium

Gas-on-gas market Oil linked market

Equator

Henry Hub

Asia Pacific –usually linked to Japanese Crude Customs prices

(lags a few months)

Price is Crude Oil factor +/- a

constant

Europe –indexation to

either crude or oil products (often based on rolling

averages)

Gas prices determined by gas-on-gas competition

Abundant unconventional

supply

High South American imports

High Middle Eastern imports

High growth in spot

delivered to Europe

Loss of Japanese coal

and nuclear

High demand growth across

Asia

Increased production

Factors increasing prices

Factors decreasing prices



Nuclear Outages in Japan Result in Higher LNG Requirements

31% of Power Generation capacity in Japan’s Eastern region is currently shut down

Outages at Japanese Nuclear facilities will result in additional LNG import requirements• ~11 MMt/y in 2011

• Japan’s LNG demand will reach 77.8 MMt/y in 2011

Japan’s LNG demand growth in the medium to long-term is driven by the expected absence of any additions in nuclear capacity and a drive towards gas in the power sector

Japan’s LNG future remains uncertain• Market participants are now having to re-evaluate

both near term and long term strategies• Thus far limited if any effect in the shipping market

as a result of recent events

Japan, Eastern Region, Total Power Generation Capacity Before and After EarthquakeJapan, Eastern Region, Total Power Generation Capacity Before and After Earthquake

Japan, Eastern Region, Electricity Production by Fuel TypeJapan, Eastern Region, Electricity Production by Fuel Type

0102030405060708090

100

Before After

OtherInterconnectionsHydroOilGas (Boiler)Gas (CCGT)CoalNuclear

GW

44%

19%

30%

1%5%1%

67%

5%

9%

4%6%9%

Gas

Coal

Nuclear

Imports

Hydro

Oil

Before March 10, 2011 After March 12, 2011




Unconventional Gas is having an Impact

North American Unconventional Gas (UG) maintain significant downward pressure on Henry Hub prices

Coal Bed Methane (CBM) for LNG export in Australia and Indonesia

In the long term increasing UG availability could impact LNG demand in areas such as China, India and Europe

Impact of Unconventional Gas per RegionImpact of Unconventional Gas per Region


Canada (Shale Gas)Current LNG application at Kitimat, planned mid-decade start-up

USA (Shale Gas)Setting market clearing Henry Hub price

Australia (CBM)Imminent application as feed gas to LNG

Indonesia (CBM)Imminent application as feed gas to LNG

China (Shale Gas)Additional domestic production Post 2020

Europe (UG)Additional domestic production Post 2020


Shale Gas Economics are Driving North American Price Levels

US Gas market is not resource-constrained for the foreseeable future US is now the world’s largest gas producer Unconventional gas has gone from ~15% of US production

in 1990 to more than 50% in 2008 Long term Henry Hub projections are around $5 / MMBtu

North American Shale Gas Cost of Service (i.e., breakeven cost)

$0

$1

$2

$3

$4

$5

$6

$/MMB

tu

2010 Monthly HH Prices

Max: $5.25/MMBtu

Avg: $4.24/MMBtu

Min: $3.35/MMBtu

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$0

$1

$2

$3

$4

$5

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$/MMB

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Max: $5.25/MMBtu

Avg: $4.24/MMBtu

Min: $3.35/MMBtu

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Shale Gas Economics are Driving North American Price Levels

US Gas market is not resource-constrained for the foreseeable future US is now the world’s largest gas producer Unconventional gas has gone from ~15% of US production

in 1990 to more than 50% in 2008 Long term Henry Hub projections are around $5 / MMBtu


$0

$1

$2

$3

$4

$5

$6

$/MMB

tu


Max: $5.25/MMBtu

Avg: $4.24/MMBtu

Min: $3.35/MMBtu

Woo

dford

Horn

Rive

r

Marce

llus

(new

tax)

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esvil

le(T

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)

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le

Barn

ett

Hayn

esvil

le(L

ouisi

ana)

Marce

llus


$0

$1

$2

$3

$4

$5

$6

$/MMB

tu


Max: $5.25/MMBtu

Avg: $4.24/MMBtu

Min: $3.35/MMBtu

Woo

dford

Horn

Rive

r

Marce

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(new

tax)

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Thank you!

Documents

Gilmore Maran Gas LNG Market Outlook