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]
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LNG market outlook Time to get liquid
October 2012
Please refer to important disclosures at the end of this document
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
*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
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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
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
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
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
Source: Company data; IEA; Pareto
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+
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%
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25%
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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
*Source: Pareto Securities, World Yards, Clarksons
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
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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)
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
Source: Pareto Securities, IEA, World Yards
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
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
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
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
Source: Pareto Securities
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
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?
Source: Pareto Securities, Platts
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
Source: Pareto Securities, Platts
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
Source: Pareto Securities, Platts
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
Source: Pareto Securities
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
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%
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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
Source: Pareto Securities
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
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
Source: HLNG, Pareto Securities
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
Source: Pareto Securities
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
Source: Pareto Securities
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
Source: Pareto Securities
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
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
*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
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 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 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
Growth 2010-2030 (lhs) CAGR 2010-2030 (rhs)
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
Growth 2008-2030 (lhs) CAGR 2008-2030 (rhs)
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
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
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
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Investment products provided by or through Auerbach Grayson & Company or Pareto Securities Research are not FDIC insured may lose value and are not guaranteed by Auerbach Grayson & Company or Pareto Securities Research. Investing in non-U.S. securities may entail certain risks. This document does not constitute or form part of any offer for sale or subscription, nor shall it or any part of it form the basis of or be relied on in connection with any contract or commitment whatsoever. The securities of non-U.S. issuers may not be registered with or subject to SEC reporting and other requirements. The information available about non-U.S. companies may be limited, and non-U.S. companies are generally not subject to the same uniform auditing and reporting standards as U.S. companies. Fluctuations in the values of national currencies, as well as the potential for governmental restrictions on currency movements, can significantly erode principal and investment returns. Market rules, conventions and practices may differ from U.S. markets, adding to transaction costs or causing delays in the purchase or sale of securities. Securities of some non-U.S. companies may not be as liquid as securities of comparable U.S. companies. Auerbach Grayson & Company and/or Pareto Securities Research may have material conflicts of interest related to the production or distribution of this research report which, with regard to Pareto Securities Research, are disclosed herein. Pareto Securities Inc. is a broker-dealer registered with the U.S. Securities and Exchange Commission and is a member of FINRA & SIPC. U.S. To the extent required by applicable U.S. laws and regulations, Pareto Securities Inc. accepts responsibility for the contents of this publication. Investment products provided by or through Pareto Securities Inc. or Pareto Securities Research are not FDIC insured, may lose value and are not guaranteed by Pareto Securities Inc. or Pareto Securities Research. Investing in non-U.S. securities may entail certain risks. This document does not constitute or form part of any offer for sale or subscription, nor shall it or any part of it form the basis of or be relied on in connection with any contract or commitment whatsoever. The securities of non-U.S. issuers may not be registered with or subject to SEC reporting and other requirements. The information available about non-U.S. companies may be limited, and non-U.S. companies are generally not subject to the same uniform auditing and reporting standards as U.S. companies. Market rules, conventions and practices may differ from U.S. markets, adding to transaction costs or causing delays in the purchase or sale of securities. Securities of some non-U.S. companies may not be as liquid as securities of comparable U.S. companies.
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Disclaimers and disclosures
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.
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Disclaimers and disclosures
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).
- Expro Intl. Group Holding - Polarcus - Wilh. Wilhelmsen
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Disclaimers and disclosures
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