An Overview of the World LNG Market and Canada’s Potential for Exports of LNG

8/10/2019 An Overview of the World LNG Market and Canadas Potential for Exports of LNG

1/44

An Overview of the World LNGMarket and Canadas Potentialfor Exports of LNG

January 2014


2/44

An Overview of the Wor ld LNG MarketAnd Canadas Potent ial for Exports o f LNG

Table of Contents

1 Introduction and Executive Summary ........................................................................ 12 Overview of the World LNG Market.......................................................................... 2

2.1 World LNG Supply .............................................................................................. 32.2 World Demand for LNG ...................................................................................... 72.3 Pricing of LNG ..................................................................................................... 9

3 LNG Supply and Demand Outlook........................................................................... 123.1 LNG Supply as a Function of World Liquefaction Capacity ............................. 133.2 Major Importers of LNG .................................................................................... 16

3.2.1 Japan ........................................................................................................... 163.2.2 South Korea ................................................................................................ 183.2.3 China ........................................................................................................... 193.2.4 Taiwan......................................................................................................... 213.2.5 India ............................................................................................................ 213.2.6 United Kingdom.......................................................................................... 223.2.7 Other Western Europe ................................................................................. 233.2.8 North America ............................................................................................ 233.2.9 South America ............................................................................................ 26

4 Canadas LNG Export Opportunity .......................................................................... 284.1 Impetus for Canadas Participation in World LNG Export Market ................... 28

4.1.2 Large Resource Base Located Near Canadas West Coast ......................... 284.1.3 Infusion of Foreign Investment ................................................................... 284.1.4 The Need for Market Diversification .......................................................... 304.1.5 Proximity to the Rapidly Growing S.E. Asian Gas Markets ...................... 314.1.6 Economic Drivers ....................................................................................... 32

4.2 Potential Canadian West Coast LNG Export Terminals. ................................... 344.3 Scale of Export Capacity and Canadas Ability to Compete ............................. 36

4.4 Market Access & Canadas Natural Gas Production Potential .......................... 374.5 First Nations ....................................................................................................... 394.6 Conclusion .......................................................................................................... 39


3/44

An Overview of the Wor ld LNG MarketAnd Canadas Potent ial for Exports o f LNG

Table of Figures

Figure 1 - World LNG Trade (Bcf/d) ................................................................................. 2Table 1 - World Conventional Natural Gas Reserves by Country as of December 31 2012(Tcf) .................................................................................................................................... 3Table 2 - World Shale Gas Resources Outside U.S. (Tcf).................................................. 4Table 3 - World Natural Gas Production by Region in the Reference Case, 2010-2040(Bcf/d) ................................................................................................................................. 5Table 4 - Global LNG Supply (Bcf/d) ................................................................................ 6Figure 2 - World Natural Gas Consumption (Bcf/d) .......................................................... 7Table 5 - Imports of LNG (Bcf/d) ....................................................................................... 9Figure 3 - Typical JCC Structured LNG Pricing Contract ............................................... 10 Table 6 - World LNG Liquefaction Capacity (Bcf/d) ...................................................... 12Figure 4: Australian Liquefaction Projects (Bcf/d) ........................................................ 15Figure 5 - Japan Imports by Source, 2012 ........................................................................ 17Figure 6 - South Korea LNG Imports by Source 2012 ..................................................... 18Figure 7: Chinese Liquefaction Capacity: Existing and Under Construction (Bcf/d) ...... 19Table 7 Existing US LNG Import Terminals ................................................................. 24Table 8: Applications Received by DOE/FE to Export Domestically Produced LNG fromthe Lower-48 States .......................................................................................................... 26Figure 8 - Western Canada Resource Plays ...................................................................... 28Figure 9 - Selected North American Gas Pipelines & Markets Traditionally Served byWestern Canadian Gas ...................................................................................................... 30Figure 10 - Selected North American Shale Plays............................................................ 31Table 9 - 2010 Average LNG & AECO Price $C/GJ ....................................................... 32Table 10 - Additional Costs Expressed on a Per MMBtu Basis ....................................... 32Figure 11 - Costs of delivering western Canadian LNG to S.E. Asia $/MMbtu .............. 33Figure 12 - Western Canadian Natural Gas Production.................................................... 38

Table 11 - Factors Affecting Canadas LNG Export Development ................................. 41


4/44

An Overview of the Wor ld LNG MarketAnd Canadas Po tential for Expor ts of LNG Page 1

1 Introduction and Executive Summary

This report provides an overview of global liquid natural gas (herein referred to as LNG)trade as it currently exists and examines the potential for future growth in this market. In

addition, the report examines the prospects for Canadas entry into this market and thefactors behind this potential entry.

World trade in LNG more than tripled over the last 15 years, growing from just over 10Bcf/d (billions of cubic feet per day) in 1997 to nearly 32 Bcf/d in 2011. It is anticipatedthat this market will continue its rapid expansion as better production technology meansmore gas reserves worldwide are available for development while demand for energy,particularly for those with cleaner-burning properties, is expected to grow. Canada isendowed with large unconventional gas resources, and its natural gas producers arebeginning pay more attention to the world LNG market potential as they develop theirplans to exploit these resources.

The current consumers of LNG are mainly to be found among the energy hungryeconomies of South East Asia as well as a number of the more developed WesternEuropean countries. Some LNG is also imported into North and South America. ThePacific Basin, which includes the economies of South East Asia, is the largest consumingregion. It is also expected to exhibit the highest future growth rate, given the underlyingeconomic growth of the countries found in this region and their burgeoning demand forenergy.

Competition for these growing markets will, however, be fierce. An examination of allthe gas liquefaction projects worldwide that are either under construction or are in the

proposal stage shows that there exists the potential to increase worldwide liquefactioncapacity by more than 100% within the next decade. In particular Australia, and to alesser extent Nigeria, could emerge as significant LNG suppliers with Australiachallenging Qatar as the worlds largest LNG exporter.

Canadas potential participation in the LNG market is being driven by a number offactors, most notably: the large resource base located near the countrys west coast; theproximity of Canadas west coast to South East Asian markets; an infusion of foreigninvestment sourced from countries that are consumers of LNG; the need for Canadianproducers to increase their market diversification; and the desire to access markets withhigher netback potentials given the relatively low natural gas prices currently found inNorth America and the historical link between LNG prices and oil prices. Asianconsumers may be wary of relying too much on a single country such as Australia fortheir future LNG needs and might look favourably on Canada as a reliable option todiversify their supply portfolios. Access to these new markets will be required for Canadato realize its production potential.


5/44


2 Overview of the World LNG Market

World trade in LNG has grown dramatically over the last fifteen years. As shown inFigure 1, trade in LNG more than tripled, growing from just over 10 Bcf/d in 1997 to 32

Bcf/d in 2012. It is anticipated that this market will continue its rapid expansion as betterproduction technology means more gas reserves worldwide are available for developmentwhile demand for energy, particularly for those with cleaner-burning properties, isexpected to grow. Canada is endowed with large unconventional gas resources, andproducers in this country are beginning pay more attention to the world LNG marketpotential as they develop their plans to exploit these resources.

Figure 1 - World LNG Trade (Bcf/d)

Source: EIA, OGJ, BP Statistical Review of World Energy

The remainder of this overview identifies the main sources of LNG supply and themarkets that currently consume LNG. It concludes with a brief general discussion of howprices are established for LNG. Section 3 provides a more detailed analysis of eachcountry that currently participates in the LNG market or has the potential to participate. Itfirst examines those countries that supply LNG before looking at those countries

consuming LNG. Section 4 provides an assessment of the drivers behind Canadaspotential participation in the LNG market and what impact the entry of Canada mighthave.

0

5

10

15

20

25

30

35

1997 2002 2008 2009 2010 2011 2012

Bcf/d


6/44


2.1 World LNG Supply

The current suppliers of LNG to world markets and those that are expected to emerge assignificant suppliers in the future come, not surprisingly, from those countries that are

endowed with the largest natural gas reserves. Table 1 (below) identifies the largest 20countries with known conventional gas reserves measured in trillions of cubic feet (Tcf).

Table 1 - World Conventional Natural Gas Reserves by Country as ofDecember 31 2012 (Tcf)

World 6614

Top20Countries 6049

1 Iran 1187

2 RussianFederation 1163

3 Qatar 885

4

Turkmenistan

618

5 US 300

6 SaudiArabia 291

7 UnitedArabEmirates 215

8 Venezuela 196

9 Nigeria 182

10 Algeria 159

11 Australia 133

12 Iraq 127

13 China 109

14

Indonesia

10315 Norway 74

16 Egypt 72

17 Canada 70

18 Kuwait 63

19 Libya 55

20 India 47

RestofWorld 565

Source: BP Statistical Review

In addition to these conventional reserves, vast resources of unconventional gas are nowbeing unlocked by better technology. Advances in horizontal drilling and hydraulicfracturing mean that shale gas that was once considered uneconomic to produce, is nowripe for production. In 20013, the United States Potential Gas Committee increased itsestimate of potential U.S. gas resources from 1,898 Tcf to 2,384 Tcf, an increase that was


7/44


largely due to the inclusion of 1,073 Tcf of potential shale gas resources, up from theprevious estimate of 686 Tcf. In June 2013, the US Energy Information Administrationcompleted an assessment of world shale gas resources that exist outside of the UnitedStates. The report examined 137 shale formations in 41 countries outside of the United

States. The report found that there was the potential to recover 6,634 Tcf and of this total,Canada comprised 573 Tcf.

Table 2 - World Shale Gas Resources Outside U.S. (Tcf)

Risked Gas In-Place Technically RecoverableResources

North America (Canada, Mexico) 4,647 1,118South America 6,390 1,431Europe 4,895 883

Africa 6,664 1,361

Asia (China, India, Pakistan, Turkey) 6,495 1,403Australia 2,046 437Total 31,138 6,634

Source: Energy Information Administration

With these large reserves of natural gas in place, the US EIA is forecasting healthygrowth in world natural gas production. As shown in Table 3 (below), world natural gasproduction is expected to increase from just over 300 Bcf/d in 2010 to 512 Bcf/d in 2040.Currently about 10% of all natural gas production finds its way into the LNG market.


8/44


Table 3 - World Natural Gas Production by Region in the Reference Case,2010-2040 (Bcf/d)

Source: EIA 2013 International Energy Outlook

As mentioned previously, it is not surprising that there is a high degree of correlationbetween those countries blessed with large natural gas reserves and those who are thelargest suppliers of LNG. Currently the countries located in the Pacific Basin that supply

the largest amounts of LNG include Malaysia, Indonesia and Australia (see Table 4). Asis discussed later in this report, Australia has a number of LNG liquefaction projects bothunder construction and in the planning stages, which should see it emerge as a muchmore significant supplier in future years. Also, the first exports of LNG from Russia haveoccurred with the completion of its Sakhalin II project, which is likely to be the first ofseveral future LNG liquefaction developments in this country.

Projections

2010 2015 2020 2025 2030 2035 2040

OECD

OECDAmericas 77.9 83.4 91.9 98.8 104.7 112.6 121.5

OECDEurope 28.6 24.7 22.1 21.9 23.5 25.3 27.2

OECDAsia 5.8 7.8 11.0 13.8 15.7 17.4 18.9

TotalOECD 112.2 115.9 124.9 134.4 143.9 155.3 167.6

NonOECD

NonOECDEuropeandEurasia 73.1 79.5 87.8 97.6 109.0 119.2 124.9

NonOECDAsia 40.6 40.8 42.9 46.4 52.6 60.2 67.2

MiddleEast

43.5 55.2

62.3 69.0 75.3

80.6

86.2

Africa 20.2 22.0 25.5 28.1 30.8 34.0 37.3

CentralandSouthAmerica 14.8 17.6 20.2 21.7 23.3 26.0 28.6

TotalNonOECD 192.3 215.0 238.7 263.0 291.1 320.0 344.2

TotalWorld 304.5 330.9 363.6 397.4 434.9 475.3 511.8


9/44


Table 4 - Global LNG Supply (Bcf/d)

Exporter 2009 2010 2011 2012

Malaysia 2.8 3 3.22 3.10Indonesia 2.5 3 2.82 2.40

Australia 2.3 2.5 2.51 2.70

Brunei 0.9 0.8 0.91 0.90

Russia 0.7 1.3 1.39 1.40

Alaska 0.1 0.2 0.2 0.10

Peru 0 0 0.5 0.50

Total Pacific Basin 9.3 10.8 11.55 11.1

Qatar 4.8 7.3 9.92 10.20

Oman 1.2 1.1 1.06 1.10Abu Dhabi 0.7 0.8 0.77 0.70

Yemen 0 0.5 0.86 0.70

Total Middle East 6.7 9.7 12.61 12.7

Trinidad 1.9 2 1.83 1.80

Algeria 2.1 1.9 1.66 1.50

Nigeria 1.5 2.3 2.5 2.60

Egypt 1.2 0.9 0.83 0.60

Norway 0.3 0.5 0.38 0.50

Equatorial Guinea 0.4 0.5 0.51 0.50Libya 0.1 0.3 0.01 0.00

Total Atlantic Basin 7.5 8.4 7.72 7.5

Total World 23.5 28.8 31.88 31.30

Source: Oil and Gas Journal & BP World Energy Statistical Review

Of those countries located in and supplying markets in the Atlantic Basin, Trinidad,Algeria and Nigeria are currently the dominant suppliers. Nigeria, however, has a numberof LNG liquefaction projects being planned and developed that should increase itsrelative significance as an LNG supplier in years to come.

Exports of LNG from the Middle East are dominated by those from Qatar, which iscurrently the largest exporter of LNG in the world. This status, however, could comeunder threat from Australia over the next decade as this country has a considerable


10/44


11/44


The current consumers of LNG are mainly to be found among the energy hungryeconomies of South East Asia as well as a number of the more developed WesternEuropean countries. Some LNG is also imported into North and South America. ThePacific Basin is the largest consuming region and is also expected to exhibit the highest

future growth rate given the underlying economic growth of the countries found in thisregion and their burgeoning demand for energy. With respect to the South East Asianimporters of LNG, Table 5 shows that Japan is by far the largest importer in this regionand in fact the whole world with more than 30 LNG import terminals currently in serviceand several more being planned. Japan currently accounts for over 35% of the entireworld wide consumption of LNG and with the substantial damage to Japanese nuclearpower generating capacity as a result of the Tsunami that occurred in March 2011, LNGimports may grow higher in the future to compensate for the loss of nuclear powergenerating capacity. China has recently emerged as a net importer of natural gas. With itsalmost insatiable demand for energy, it is expected to become a major importer of LNGin the future. India is also expected to increase its future demand for LNG.

The developed economies of Western Europe imported 6.6 Bcf/d in 2012, down from 8.7Bcf/d in 2011 as the economics of the region continue to struggle. These nations are notexpected to increase their demand for LNG anywhere near the same rate as the growingAsian economies. LNG is also consumed in the Americas, but as will be discussed in themore detailed country analysis, the emergence of shale gas in North America means thatthis region is more likely to become a net exporter of LNG rather than an importer.


12/44


Table 5 - Imports of LNG (Bcf/d)

2009 2010 2011 2012

France

1.26 1.34 1.41 1

Spain 2.56 2.66 2.34 2.1

Portugal 0.29 0.3 0.3 0.4

Turkey 0.54 0.77 0.6 0.7

Belgium 0.62 0.63 0.64 0.4

Italy 0.27 0.88 0.85 0.7

Greece 0.08 0.11 0.13 0

UK 1.02 1.81 2.45 1.3

US 1.2 1.18 0.97 0.5

PuertoRico 0.07 0.08 0.07 0

Dom.Republic

0.05 0.08 0.09 0

Mexico 0.34 0.55 0.39 0.5

Brazil 0.07 0.27 0.1 0.3

Argentina 0.09 0.16 0.42 0.5

Chile 0.06 0.3 0.37 0.4

Canada 0.08 0.19 0.32 0.2

Kuwait&UnitedArabEmirates 0.09 0.27 0.43 0.4

TotalAtlanticBasin&Americas 8.71 11.59 11.88 9.4

Japan 8.39 9.04 10.34 11.5

SouthKorea

3.36 4.3 4.77 4.8

Taiwan 1.07 1.45 1.58 1.6

India 1.18 1.18 1.65 2

China 0.72 1.23 1.61 1.9

TotalPacificBasin 14.71 17.21 19.95 21.8

WorldTotal 23.42 28.79 31.83 31.2

Source: OGJ & BP World Energy Statistical Review

2.3 Pricing of LNG

Given the capital-intensive nature of liquefaction projects, long-term ship or paycontracts are used to ensure high utilization rates and to meet investment hurdle rates. InAsia almost all LNG is sold under long term contracts based on oil prices. In Japan,contracts are linked to the Japanese Customs Cleared (JCC) price for crude oil which is


13/44


the price of a basket of crude oil types imported in Japan that is tracked by the Japanesegovernment. The chart below shows a typical price structure for LNG negotiated on thebasis of the JCC. Thus for example, with a security of supply premium of $0.5/MMbtu(shown as ain Figure 3) and an LNG slope of JCC of 0.15, (shown as bin Figure 3) this

would result in an LNG price of $15.5/MMbtu if the JCC price was $100 per barrel.

Figure 3 - Typical JCC Structured LNG Pricing Contract

Some market observers have questioned, however, whether these types of contractingarrangements will continue to predominate, particularly if oil continues to trade at asignificant premium to natural gas. In addition, a proliferation of LNG liquefaction plantsbeing planned and developed throughout the world will bring on significant sources ofnew supply. Thus we may see the emergence of Henry Hub linked contracts in Asia as analternative pricing formula to oil. Also, while the spot market for LNG is comparativelysmall today compared to those volumes of LNG sold under long term contracts, anysurplus of supply situation could lead to more deals being made on a spot basis.1Otherseasoned market observers dispute that there will be a significant move away from thecurrent trend of oil-indexed long term LNG contracts in Asia. These observers contendthat the majority of suppliers will still prefer oil-indexation because of the transparency,reliability and traditional acceptance by all players.

1In late 2011, Cherniere Energy Partners announced that it had signed commercial arrangements withseveral customers at its Sabine Pass LNG project that involve a fixed capacity charge to cover the costs ofliquefaction and then to buy LNG at 115% of the Henry Hub natural gas price.

LNG = a + b*JCCLNGP

rice($/MMBtu)

JCC Price ($/bbl)

LNG price at parity withcrude oil on energyequivalence basis

LNG = a + b*JCCLNGP

rice($/MMBtu)

JCC Price ($/bbl)


LNGP

rice($/MMBtu)

JCC Price ($/bbl)



14/44


The evolution of contracting practices that took place during the deregulation of naturalgas markets in North American may hold some clues as to what might occur in the globalcontext. Shortly after North American natural gas markets were deregulated in the mid tolate 1980s, the level of Canadas exports of natural gas to the United States soared.

Initially a significant portion of these exports took place under long term contracts wherenatural gas prices were either fixed with some provision for escalation over the contractlife or were linked to prices of competing sources of energy, such as oil. Over time,however, the North American market moved away from such long term contractingpractices and Canadian exports have been sold essentially on a spot basis. This change inpractice occurred as Canadian production grew and the market became more comfortablecontracting on a short term basis as fears around supply security subsided.

In the case of the global LNG market, over the past few decades suppliers have beenchallenged to keep up with the pace of demand. Consumers of LNG have placed apremium on security of supply and have been willing to sign up for long term contracts.

LNG suppliers have in turn sought long term contracts to underpin the large capitalinvestments involved. As a result, to date the spot market for LNG has been very limitedcompared to the size of the market overall.

This trend could change if those countries that are aggressively seeking to expand theirLNG liquefaction capacity create surplus of supply in world LNG markets. More intensegas on gas competition would see the emergence of a larger spot market with lessvolumes being sold on a long term basis with prices linked to those of crude oil. Australiaalone has a series of LNG export projects in various stages of development that couldincrease this countrys export capacity from 2.5 Bcf/d today to over 16 Bcf/d in 2018.Thus if the anticipated high rates of growth in demand in the emerging South East Asian

economies of China and India fail to take place as anticipated, a surplus of supply ofLNG will translate into a more significant spot market with prices reflecting greater gason gas competition and less linkage to oil prices.


15/44


3 LNG Supply and Demand Outlook

As was discussed in section 2, there are a large number of countries that currentlyparticipate as suppliers or consumers in the world-wide LNG market. In the future even

more countries are expected to participate as new sources of supply become developedand more countries seek to rely on the clean-burning properties of natural gas to meettheir energy needs. This section begins by looking at the outlook for new liquefactioncapacity that is expected to add to the worlds supply of LNG. The section concludes byexamining more closely those countries that currently consume LNG and their prospectsfor future growth.

2

Table 6 - World LNG Liquefaction Capacity (Bcf/d)(Includes Facilities that are Existing, Under Construction & Proposed)

2011 2012 2013 2014 2015 2016 2017 2018 2019

Algeria 3.08 3.08 4.36 4.36 4.36 4.36 4.36 4.36 4.36

Angola 0.00 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73Australia 2.79 3.39 3.39 6.68 9.73 12.15 15.46 16.30 16.30

Brunei 1.01 1.01 1.01 1.01 1.57 1.57 1.57 1.57 1.57

Canada 0.00 0.00 0.00 0.00 0.25 0.25 0.98 1.99 3.78

Egypt 1.71 1.71 1.71 1.71 2.41 2.41 2.41 2.41 2.41

Equatorial Guinea 0.52 0.52 0.52 0.52 0.52 1.13 1.13 1.13 1.13

Indonesia 4.21 4.21 4.21 4.48 4.48 4.48 4.48 4.48 4.48

Libya 0.32 0.32 0.32 0.32 0.32 0.32 0.32 0.32 0.32

Malaysia 3.36 3.36 3.36 3.36 3.36 3.81 3.81 3.81 3.81

Nigeria 2.96 2.96 2.96 2.96 8.83 8.83 8.83 8.83 8.83

Norway 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59Oman 1.44 1.44 1.44 1.44 1.44 1.44 1.44 1.44 1.44

Papua New Guinea 0.00 0.00 0.00 0.92 0.92 0.92 0.92 0.92 0.92

Peru 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62

Qatar 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78

Russia 1.34 1.34 1.34 1.34 1.34 3.65 5.33 5.33 5.33

Trinidad 2.16 2.16 2.16 2.16 2.88 2.88 2.88 2.88 2.88

UAE 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78

United States 0.00 0.00 0.00 0.00 2.52 2.52 7.18 11.38 11.38

Yemen 0.94 0.94 0.94 0.94 0.94 0.94 0.94 0.94 0.94

Total 38.61 39.94 41.22 45.70 59.38 65.18 75.55 81.60 83.39

Source: Petroleum Economist

2Information on Japan, South Korea, India & China, is taken in part from the Energy InformationAdministration Country Briefs. Information on the other countries examined is taken from a variety ofsources including corporate reports and presentations as well as government websites.


16/44


3.1 LNG Supply as a Function of World Liquefaction Capacity

Qatargas, established in 1984, pioneered the Liquefied Natural Gas (LNG) Industry inQatar. Today, Qatargas is the largest LNG producing company in the world, with an

annual LNG production capacity of 42 million tonnes per annum (MTA). Qatargas hasseven LNG trains, of which four are the largest in the world, each with a productioncapacity of 7.8 MTA. A second company, RasGas, oversees and manages the operationsassociated with seven LNG trains in Qatar, for which it has a total production capacity ofapproximately 37 million tonnes per annum. Much of this development has come onstream in recent years so that with a total of 79 million tonnes per annum of LNGcapacity, Qatar has emerged as the worlds leading LNG producer and exporter.

Table 6 shows that there exists the potential for a huge increase in liquefaction capacityover the next six to seven years. An examination of all the projects world-wide that areeither under construction or are in the proposal stage shows that there exists the potentialto increase liquefaction capacity by more than 100% within the next decade. The tableshows that in particular Australia, and to a lesser extent Nigeria, could emerge assignificant LNG suppliers with Australia challenging Qatar as the worlds largest LNGexporter. In addition, the United States has seen a number of LNG export projectsannounced in the last couple of years. The prospects for LNG exports from the US arediscussed in more detail in section 3.28 of this report.

It is, however, unlikely that all the projects identified in Table 6 will proceed, at least inthe timeframe currently contemplated. There are a limited number of LNG Engineering,Procurement and Construction (EPC) contractors and in Australia, for example,conventional LNG developments will be competing with Coal seam gas-to-LNG forscarce resources. This is likely to lead to an overheated construction market in Australia,and rising costs may have a negative impact on project timing.

Australias North West Shelf LNG project has been in service since 1989 and has nowgrown to 5 trains that have a combined liquefaction capacity of 2.14 Bcf/d. As a result ofseveral new natural gas discoveries, there has in recent hears been considerable activitywith respect to developing new LNG production projects in Western Australia. Theseinclude:

The Pluto project is located near Karratha, offshore Western Australia. WoodsideEnergy owns 90 percent of the venture supported by 15-year contracts withKansai Electric and Tokyo Gas at 5 percent equity each. The project includes anoffshore platform connecting 5 subsea wells and a 112-mile pipeline to anonshore LNG facility on the Burrup Peninsula. The first train came online in 2012with a capacity of 0.55 Bcf/d.

The Gorgon project, led by Chevron (50%), with Shell and ExxonMobil (25%each), is currently under construction. The Gorgon gas field, which is 80-124miles off the northwest coast, is believed to contain 40 Tcf of natural gas and is


17/44


currently Australia's largest known natural gas resource. The project includesdevelopment of the Gorgon gas fields with subsea pipelines to Barrow Island; agas processing facility on the island with production capacity of 2.05 Bcf/d,consisting initially of three, 0.68 Bcf/d LNG trains; LNG shipping facilities to

transport products to international markets; and greenhouse gas management viainjection of carbon dioxide into deep formations beneath Barrow Island. TheGorgon joint venture is investing approximately $2 billion in the design andconstruction of the world's largest commercial-scale CO2 injection facility toreduce the project's overall greenhouse gas emissions by between 3.4 and 4.1million tonnes per year. The project is expected to be in service by Q1 2015.

The Ichthys project, that is still in the planning stages, is led by Japan's INPEX(74%) and Total (26%), is also located offshore the northwest coast in the BrowseBasin. It is expected to produce LNG, LPG, and condensate for export to Japanand elsewhere via a 528-mile undersea pipeline connecting the fields to a newexport LNG terminal to be built near Darwin. When the project comes onstream

in 2016, its production is expected to be at least 1.1 Bcf/d.

The Wheatstone project is currently under construction and its largest owners areChevron (64%) and Apache (13 %). Sales and purchase agreements have beensigned with Tokyo Electric Power Company, and Kyushu Electric PowerCompany. The first stage of the project consists of two trains with a combinedcapacity of 1.2 Bcf/d, however, the project has approval to expand to 3.28 Bcf/d.Wheatstone is expected to go into service in 2016.

In May 2011, Shell announced that it has taken the final investment decision toproceed with its Prelude Floating Liquefied Natural Gas (FLNG) Project inAustralia. Moored some 200 kilometres from the nearest land in Australia, the

FLNG facility will produce gas from offshore fields, and liquefy it onboard thesame facility. Shell retains a 67.5% interest in the project while Inpex has a 17.5%interest, Kogas has 10% and CPC has 5%.The FLNG facility will tap around 3Tcf equivalent of resources contained in the Prelude gas field. Shell discoveredthe Prelude gas field in 2007. Expected production from Prelude is 5.3 milliontonnes per annum (mtpa) of liquids, comprising 3.6 mtpa of LNG (0.47 Bcf/d),1.3 mtpa of condensate and 0.4 mtpa of liquefied petroleum gas. Production istargeted to commence in 2017.

These projects are not only competing with each other but also with three significant coalseam-gas-LNG projects located in the eastern Australian state of Queensland. Theseprojects include:

Australia Pacific LNG, sponsored by Origin Energy, Sinopec and ConocoPhilips.This project will consist of two trains with a combined production capacity of1.18 Bcf/d. First LNG exports are anticipated in 2015


18/44


Gladstone LNG, sponsored by Santos, Petronas, Kogas and Total. This projectconsists of 2 trains with a combined capacity of 0.82 Bcf/d. First cargoes areexpected to be shipped by 2015

Queensland Curtis, sponsored by BG, will in its first stage consist of two trains

with a combined capacity of 1.11 Bcf/d. First LNG delivery is expected to be in2014. The project can be expanded to three trains to obtain a total of 1.6 Bcf/d ofcapacity.

The challenges of a limited number of LNG EPC contractors and the impacts of anoverheated construction market will not only be felt in Australia but will also be feltworldwide, likely resulting in some projects being cancelled or significantly delayed.Regardless of this fact, however, it appears that the world is undoubtedly in line for asubstantial increase in liquefaction capacity over the next several years.

Figure 4: Australian Liquefaction Projects (Bcf/d)

Nigeria, which is currently one of the larger exporters of LNG, also has plans tosignificantly increase its production. Its output currently comes from the NigeriaLiquefied Natural Gas (NLNG) facility on Bonny Island. This facility has 6 trainscurrently in operation but plans for building a 7

thtrain that would lift total production

capacity to over 30 Million tonnes per annum (4.2 Bcf/d) are currently at an advancedstage. Additional future projects include Brass LNG, a project that is owned by Nigerian


19/44


National Petroleum Corporation (NNPC) and ConocoPhillips that proposes to have twotrains with a total capacity of 10 Million tonnes per annum (1.4 Bcf/d). An in-service dateof 2015 is currently envisaged. At a much earlier stage of development is the OKLNGproject that would comprise 4 trains for a total export capacity of 22 Million tonnes per

annum (3.8 Bcf/d). The project sponsors of this development include NNPC, Chevronand BG Group. An in-service date has yet to be announced.

With the potential for such a marked increase in LNG supply on the horizon, it isimportant to examine the prospects for world demand to soak up these incrementalsupplies. The continuation of significantly higher prices being realized today on worldLNG prices compared to their North American counterparts will hinge, in large part, onthe ability of world demand growth to keep up with the additional supplies beingforecast. The remainder of this section looks more closely at the countries that importLNG today and those expected to import LNG in the future to assess the prospects forworld demand growth for LNG.

3.2 Major Importers of LNG

3.2.1 Japan

Japan has only very limited domestic supplies of natural gas and as a populous countrywith a highly developed economy, it has emerged as the worlds largest consumer ofLNG.

Inpex and other companies created from the former Japan National Oil Company are theprimary players in Japan's domestic natural gas sector, as in the oil sector. Inpex,

Mitsubishi, Mitsui, and various other Japanese companies are actively involved indomestic as well as overseas natural gas exploration and production. Osaka Gas, TokyoGas, and Toho Gas are Japan's largest retail natural gas companies, with a combinedshare of about 75 percent of the retail market. Japanese retail gas and electric companiesare participating directly in overseas upstream LNG projects to assure reliability ofsupply.

Japan began importing LNG from Alaska in 1969, making it a pioneer in the global LNGtrade. Due to environmental concerns, the Japanese government has encouraged naturalgas consumption in the country and Japan accounted for about 37 percent of global LNGimports in 2012. In 2010, Japan imported slightly more than 9 Bcf/d of LNG while in2011 the level of imports rose to 10.34 Bcf/d and increased further to 11.5 Bcf/d in 2012according to the BP Statistical Review.

The increase in imports post 2010 is a direct result of the March 11, 2011 earthquake asthe country has had to import more spot LNG along with other fuels to cover the nuclearpower outages that occurred. Only one small regasification terminal, Shin Minato LNG,


20/44


shut down as a result of the recent earthquake, allowing the country to continue importingLNG and potentially compensate for some portion of lost nuclear capacity.

The power sector is the largest consumer of LNG, followed by the industrial sector.

Increased use of natural gas within these sectors has been one of the main drivers ofgrowth of natural gas demand in Japan.

Japan has over 30 operating LNG import terminals with a total throughput capacity wellin excess of historical levels of demand in order to assure flexibility. The majority ofJapans LNG terminals are located in the main population centers of Tokyo, Osaka, andNagoya, near major urban and manufacturing hubs, and are owned by local powercompanies, either alone or in partnership with gas companies. These same companiesown much of Japan's LNG tanker fleet.

Figure 5 - Japan Imports by Source, 2012

Other: includes Peru, US, Trinidad, Algeria, Egypt, Yemen


Japanese regulations permit individual utilities and natural gas distribution companies tosign LNG supply contracts with foreign sources, in addition to directly importing spotcargoes. The largest LNG supply agreements are held by Tokyo Gas, Osaka Gas, Toho


21/44


Gas, Chubu Electric and TEPCO, primarily with countries in Southeast Asia and theMiddle East. Many of Japan's existing LNG contracts date from the 1970s and 1980s, andare set to expire over the next decade. Some industry analysts suggest that this is drivingJapanese firms' interest in acquiring equity stakes in foreign LNG projects, in an effort to

guarantee future supply. In addition to long-term contracts, Japan receives a significantnumber of spot cargoes.

Contracted imports remain vital to the country, however, which has led to therenegotiation of long-term supply deals, especially with Indonesia, one of Japan's largestLNG suppliers. Japanese companies are also actively involved in either being partners ofcustomers of a number of new LNG projects that are being developed all around theworld as the country seeks to diversify its sources of LNG supply.

3.2.2 South Korea

There are four LNG regasification facilities in South Korea, with a total capacity of 6.85Bcf/d. KOGAS operates three of these facilities (Pyongtaek, Incheon, and Tong-Yeong),accounting for more than 97 percent of current capacity. Pohang Iron and SteelCorporation (POSCO) and Mitsubishi Japan jointly own the only private regasificationfacility in Korea, located on the Southern Coast in Gwangyang. In 2012, South Koreaimported 4.8 Bcf/d of LNG. KOGAS purchases most of its LNG through long-termsupply contracts, and uses spot cargos primarily to correct small market imbalances.About 73 percent of 2012 natural gas imports came from Qatar, Malaysia, Oman, andIndonesia.

Figure 6 - South Korea LNG Imports by Source 2012



22/44


Twenty-three percent of current regasification capacity has been added since 2005. Inaddition to recent expansion of existing facilities, KOGAS is currently constructing anew receiving facility in Samcheok, on the Northwest coast. The first stage of the 0.76Bcf/d facility is slated for 2013 completion, with supplies of 350 Bcf to be met primarily

through gas imported from Vladivostok, Russia starting in 2015. Although the associated2008 KOGAS-Gazprom memorandum of understanding indicated that the gas could beimported either as LNG or via pipeline from Vladivostok, Russian and Korean leadersrecently acknowledged that the pipeline construction option will most likely not bedeemed economically feasible without the cooperation of North Korea.

3.2.3 China

China began imports of LNG with the completion of its Guandong LNG terminal thatbecame operational in 2006. Since that time a number of other LNG terminals havebecome operational including: Shanghai LNG; Fujan LNG; Rudong LNG; and DalianLNG. The total import capacity of these facilities is 2.9 Bcf/d, and in 2012 Chinaimported 1.93 Bcf/d of LNG. As shown in Figure 7, China is currently constructingadditional LNG facilities so that by 2015 the capacity for LNG imports will exceed 6Bcf/d.

Figure 7: Chinese Liquefaction Capacity: Existing and Under Construction(Bcf/d)


23/44


The above chart does not include expansion capacity that would be added throughadditional phases to the Rudong, Dalian and Tangshan LNG facilities as the timing forthese expansions has yet to be confirmed.

In addition to developing these LNG import terminals, China has also invested in longterms sales contracts for LNG with a number of global suppliers. Given thesedevelopments it is clear that Chinese imports of LNG will increase in the future, but theultimate level of such imports will depend heavily on a number of other factors. Thesefactors include the success China may have in developing its own considerable reservesof natural gas which include 124 Tcf of proven reserves while technically recoverableshale gas resources have been estimated by the EIA to amount to 1,115 Tcf .

In addition to domestic production, China has the opportunity to import gas via pipelineand currently imports around 2 Bcf/d of gas via pipeline from the giant Galkynysh fieldin Turkmenistan. In 2008, China National Petroleum Corporation (CNPC) and

Turkmengaz signed a sales agreement that targeted an import volume of 3.8 Bcf/d of gasby 2015. The two companies have since signed a contract for additional supplies of 2.41Bcf/d as further stages of the Galkynysh field are developed.

In August 2013, after three years of construction, the Myanmar-China natural gaspipeline has started deliveries. The 793 km pipeline starts at Kyaukpyu on Myanmarswestern coast and enters southwestern Chinas Yunnan province. The pipeline, whenoperating at capacity, will be capable of delivering as much as 1.2 Bcf/d of natural gas toChina.

In March 2013, Russia signed a preliminary gas supply deal with China, comprising a

framework whereby Gazprom would supply 3.7 Bcf/d of gas for 30 years commencing in2018, which would eventually rise to as much as 5.8 Bcf/d. It is important to note,however, that the terms of the deal have yet to be finalized neither with respect to routenor with respect to price for the gas.

Despite having a variety of supply options, LNG imports to China can be expected togrow in the future, particularly as new LNG import infrastructure is currently underdevelopment. Over the past decade Chinese energy demand has almost tripled and itsheavy traditional reliance on coal is not sustainable as it has come with a considerableenvironmental cost. Air pollution in Beijing has been reaching dangerous levels. TheChinese government has recently issued an Atmospheric Pollution Prevention ActionPlan which targets a peak in coal consumption by 2017 and to reduce the level of airparticulates by up to 25%. As part of this initiative the government plans to ban newcoal-fired power plants in provinces surrounding Beijing, Shanghai and Guangzhou.Chinas most recent 5 year plan (its 12thextending from 2011 to 2015) aims to cut theamount of energy and carbon dioxide emissions per unit of economic output by 16% and17% respectively, over the duration of the plan. Displacement of coal-fired power plantswith natural gas fired power plants would aid country in meeting these targets given the


24/44


much lower emission rates of natural gas compared to coal. As a result the Chinesegovernment anticipates boosting the share of natural gas as part of total energyconsumption to 10 percent by 2020 to alleviate high pollution from the country's heavycoal use and diversify the fuel mix in all end-use sectors.

Taking into account these ambitious targets for increasing the natural gas share ofChinas overall energy mix, the EIA is forecasting growth in natural gas consumption inChina of 360%, from 10.4 Bcf/d in 2010 to 47.9 Bcf/d in 2040.

3.2.4 Taiwan

Taiwans consumption of natural gas is projected to increase to 1.8 Bcf/d by 2020 and 2.1Bcf/d by 2025, up 55% and 77% respectively, from 1.17 Bcf/d in 2009, according to itsBureau of Energy, Ministry of Economic Affairs, as it strives to cut down on its coalrequirements. Regasified natural gas from LNG imports provides the vast majority ofTaiwans natural gas, while domestic supply provides only a minimal amount. In 2012the country imported 1.6 Bcf/d of LNG. The main consumers of Taiwans natural gas areits eight power generators who account for a combined total of 78.4%, with theoutstanding amount taken by energy (3.9%), industrial (7.5%), services (3%) andresidential (7.2%) users.

The government owned Chinese Petroleum Corporation (CPC), which operates under theMinistry of Economic Affairs, currently controls all aspects of natural gas supply inTaiwan, including exploration, production, imports and wholesale sales. CPC constructedand operates two LNG terminals, the Yungan LNG receiving terminal located in southernTaiwan, which has an official handling capacity of 1.02 Bcf/d a day. CPC has alsoconstructed a second receiving terminal and associated infrastructure in Taichung inTaiwans north. The receiving terminal has a capacity of 0.4 Bcf/d. An increase in thecountrys liquefaction capacity will be required if it is to meet its gas consumption goals.

3.2.5 India

In 2012, India imported 2 Bcf/d of LNG, over 80 percent of it from Qatar. India importsLNG through both long-term contracts and spot shipments.

India now has three operational LNG import terminals, Dahej, Hazira and its Dabholterminal that recently became operational in early 2012. India received its first LNG

shipments in January 2004 with the start-up of the Dahej terminal in Gujarat state.Petronet LNG, a consortium of state-owned Indian companies and international investors,owns and operates the Dahej LNG facility with a capacity of 5 million tons per year(mtpa) (0.65 Bcf/d). Indias second terminal, Hazira LNG, started operations in April2005, and is owned by a joint venture of Shell and Total. The facility has a capacity of2.5 mtpa (0.3 Bcf/d), which may be expanded to 5 mtpa (0.65 Bcf/d) in the future.


25/44


The 5 mtpa (0.65 Bcf/d) LNG processing plant in Dabhol was recently commissioned butthe new facility will not be building up to full capacity quickly, however. A protectiveouter breakwater that will deflect ocean swells, especially during the June-Septembermonsoon season, is still under construction and will not be ready until late 2013. Until

that time the terminal will not be able to be operated beyond 30-40 per cent of its ratedcapacity, i.e. a maximum 2 million tonnes per annum out of its 5 million tonnes perannum potential.

In addition to the 3 plants currently in operation, construction of LNG Receiving, Storage& Regasification Terminal at Kochi is in full swing. The terminal is to have a capacity of5 MMTPA, and is likely to be commissioned by the end of 2012. The facility has secureda 1.5 mtpa (0.20 Bcf/d) supply from Australias Gorgon LNG project.

Long-term growth in demand for LNG remains unclear however, as price is an issue ofcontention in India and increasing domestic natural gas production is expected from

eastern offshore fields. Industry analysts note that Indian companies appear unwilling tocommit to long-term LNG supply contracts at international prices. While negotiations arecurrently underway for several long-term LNG supply deals, whether or not Indias bidswill be accepted is questionable in light of the low prices that India has offered to pay.Instead, India is becoming an important destination for spot LNG cargoes.

3.2.6 United Kingdom

The UK has been emerging as a significant importer of LNG as domestic natural gassupplies decline with imports of LNG reaching a level of 2.45 Bcf/d in 2011. In 2012,however, imports of LNG declined to 1.3 Bcf/d as the economy struggled to avoidrecession which resulted in weak consumption growth in natural gas. Imports of LNGare projected to recover as the UK faces a need to fill gas storage and to offset persistentdeclines in domestic production.

Currently, the UK has four LNG import terminals. The longest operating LNG terminalin the UK is National Grids Grain LNG terminal on the Isle of Grain. The facilityoriginally became operational in 2005 when Phase I of the construction was completed.Additionally, Phase II has been completed in 2009 and Phase III completed in 2011. Withthe completion of Phase II, the terminals capacity increased to 1.4 Bcf/d. With Phase 3complete, National Grid has expanded the facility to 2 Bcf/d in time for the 2010/2011winter. Construction works of Grain LNG Phase 4 are planned to start in the end of 2013and commercial operations are envisaged to commence by winter 2016/17. The plannedGrain LNG Phase 4 will expand the total yearly import capacity of the Grain LNGTerminal by up to 0.8 Bcf/d.

Teesport LNG, operated by the U.S.-based Excelerate Energy, commenced commercialoperation in February 2007. This was the first dockside regasification port and the secondoperational LNG facility in the UK Teesport LNG can deliver up to 0.60 Bcf/d of naturalgas to the UK market.


26/44


The Dragon LNG terminal, a collaboration of BG, Petronas, and 4Gas, commencedoperation in September 2009. The import, storage, and regasification terminal is locatedin Milford Haven in South Wales and has a sendout capacity of 0.8 Bcf/d.

The South Hook LNG terminal, also located in Milford Haven, Wales, is owned andoperated by Qatar Petroleum, ExxonMobil, and Total. Now that it has completed itsphase II, the facilities are capable of sending out 2 Bcf/d of gas to the UK national grid.

3.2.7 Other Western Europe

Spain has traditionally been Europes largest importer of LNG with six LNG importterminals capable of regasifying up to 5 Bcf/d. In 2012, Spain imported 2.1 Bcf/d,marginally down from a year earlier as the economy struggled to recover from weakdemand associated with the recession. Although gas demand in Spain should recover infuture years, LNG imports to this country face competition from the start-up of theMedgaz pipeline which can bring 0.8 Bcf/d of gas from Algeria to Spain.

France has three LNG import terminals that can regasify 2.25 Bcf/d of LNG. In 2012France imported 1.0 Bcf/d of LNG. Belgium has one LNG terminal that can regasify 0.9Bcf/d of LNG and in 2012 Belgium imported just over 0.4 Bcf/d. Both France andBelgium are well supplied by natural gas pipelines that compete with LNG facilities tomeet these countries natural gas needs.

Other significant European importers of LNG include Turkey, Italy, Portugal and Greece.In 2012, these countries combined imported 1.8 Bcf/d. None of these countries isanticipated to see a major increase in future LNG consumption.

3.2.8 North America

In Canada, the Canaport LNG terminal in Eastern Canada commenced operation in 2009.This terminal, that has a sendout capacity of 1.0 Bcf/d, exports these natural gas volumesto U.S. Northeast markets.

Since the early part of the last decade there has been a flurry of construction of newimport terminals in the United States as declines in conventional natural gas productioncreated the perception that more LNG imports would be required to meet an anticipatedenergy shortfall. Table 7 below shows that there are now 11 LNG import terminals in the

United States with a combined capacity of 18.5 Bcf/d. However, the emergence ofunconventional shale gas production has reversed the decline in Lower 48 state gasproduction and reduced the need for LNG imports. Despite the addition of considerableLNG import capacity, US imports of LNG have hovered around 1 Bcf/d for the past year.Indeed, some terminals have applied for and received permission to re-export deliveredLNG.


27/44


Table 7 Existing US LNG Import Terminals

Import Terminal Location/Size/Operator

A. Everett MA : 1.035 Bcf/d (GDFSUEZ - DOMAC)

B. Cove Point MD : 1.8 Bcf/d (Dominion -Cove Point LNG)

C. Elba Island GA : 1.6 Bcf/d (El Paso -Southern LNG)

D. Lake Charles LA : 2.1 Bcf/d (SouthernUnion - Trunkline LNG)

E. Offshore Boston: 0.8 Bcf/d (ExcelerateEnergy NortheastGateway)

F. Freeport TX: 1.5Bcf/d(Cheniere/FreeportLNG Dev.)

Note: Has been authorizedto re-export delivered LNG

G. Sabine LA: 4.0 Bcf/d(Cheniere/Sabine PassLNG)


H. Hackberry LA: 1.8 Bcf/d (Sempra -Cameron LNG)


I. Offshore Boston MA : 0.4 Bcf/d (GDFSUEZ Neptune LNG)

J. Sabine Pass TX: 2.0 Bcf/d (ExxonMobil

Golden Pass) (Phase I &II)K. Pascagoula MS: 1.5 Bcf/d (El

Paso/Crest/Sonangol - GulfLNG Energy LLC)

Source: Federal Energy Regulatory Commission

Over the past few years, the focus in the US has been in the development of LNG exportcapacity as a surge in unconventional gas production has dramatically increased lower 48natural gas supplies. In May 2011 the Department of Energy gave Cherniere Energy the

authorization to export up to 2.2 Bcf/d of LNG from its Sabine Pass terminal in CameronParish, Louisiana for 20 years to any country. Export operations are envisaged to start upin 2015. However, in December 2011 the department announced that it would not grantadditional licences to export domestically produced natural gas to international marketsuntil completing a review of cumulative economic impacts of liquefaction projects on USmarkets. This review was undertaken by NERA Economic Consulting and completed inDecember 2012. The report concluded that over a wide range of assumptions about


28/44


levels of exports, global market conditions, and the cost of domestic production of naturalgas, the U.S. was projected to gain net economic benefits from allowing LNG exports.One of the aspects the study focused on is the impact of LNG exports from the US ondomestic natural gas prices and its findings agreed with number of other studies that have

addressed this issue by concluding that the impact of LNG exports on LNG prices isexpected to be minimal. These conclusions are primarily driven by the fact that the priceelasticity of the gas supply curve has increased post shale gas revolution so the marketcan adjust to LNG exports with a very moderate increase in price.

Following the granting of an export licence to Cherniere the US DOE has granted exportlicences to three other operators in order that they can ship LNG to countries that do nothave free trade agreements with the U.S. These projects are the Dominion Resourcesfacility on Chesapeake Bay that will have an export capacity of 0.77 Bcf/d; the FreeportLNG project located in Quintana Island, Texas that will have an export capacity of 1.4Bcf/d; and the Lake Charles LNG project located in Louisiana that will have a capacity of

2 Bcf/d.

Table 8 provides a listing of all the projects that have applied to the US Department ofEnergy for an export licence. The final number of projects that will be granted exportlicence approval is a matter of conjecture as the benefits of granting such licencescontinues to be the subject of political debate.


29/44


Table 8: Applications Received by DOE/FE to Export Domestically ProducedLNG from the Lower-48 States

Company Quantity (a) FTA Applications (b)(Docket Number) Non-FTA Applications (c)(Docket Number)Sabine Pass Liquefaction, LLC 2.2 billion cubic feet

per day (Bcf/d)Approved (10-85-LNG) Approved (10-111-LNG)

Freeport LNG Expansion, L.P. andFLNG Liquefaction, LLC

1.4 Bcf/d Approved (10-160-LNG) Under DOE Review (10-161-LNG)

Lake Charles Exports, LLC 2.0 Bcf/d (e) Approved (11-59-LNG) Under DOE Review (11-59-LNG)Carib Energy (USA) LLC 0.03 Bcf/d: FTA

0.01 Bcf/d: non-FTAApproved (11-71-LNG) Under DOE Review (11-141-LNG)

Dominion Cove Point LNG, LP 1.0 Bcf/d Approved (11-115-LNG) Under DOE Review (11-128-LNG)Jordan Cove Energy Project, L.P. 1.2 Bcf/d: FTA

0.8 Bcf/d: non-FTA (g)Approved (11-127-LNG) Under DOE Review (12-32-LNG)

Cameron LNG, LLC 1.7 Bcf/d Approved (11-145-LNG) Under DOE Review (11-162-LNG)Freeport LNG Expansion, L.P. andFLNG Liquefaction, LLC (h)


Gulf Coast LNG Export, LLC (i) 2.8 Bcf/d Pending Approval (12-05-LNG)

Under DOE Review (12-05-LNG)

Cambridge Energy, LLC 0.27 Bcf/d Withdrawn (12-18-LNG) n/aGulf LNG Liquefaction Company,LLC


LNG Development Company, LLC(d/b/a Oregon LNG)


SB Power Solutions Inc. 0.07 Bcf/d Approved (12-50-LNG) n/aSouthern LNG Company, L.L.C. 0.5 Bcf/d Approved (12-54-LNG) Under DOE Review (12-100-LNG)Excelerate Liquefaction SolutionsI, LLC

1.38 Bcf/d Approved (12-61-LNG) n/a

Golden Pass Products LLC 2.6 Bcf/d Pending Approval (12-88-LNG)

n/a

Cheniere Marketing, LLC 2.1 Bcf/d Pending Approval (12-99-LNG)


Main Pass Energy Hub, LLC 3.22 Bcf/d Pending Approval (12-114-LNG)

n/a

CE FLNG, LLC 1.07 Bcf/d Pending Approval (12-123-LNG)


Total of all Applications Received 27.42 Bcf/d 19.73 Bcf/d

Plans to export Alaskan sourced natural gas as LNG have also been announced, althoughthe timing of this project is likely further out into the future than those listed above. BPPLC, Exxon Mobil Corp, ConocoPhillips Co. and TransCanada Corp are backers behindthe Alaska Southcentral LNG project that would include construction of a 1,300-kilometer pipeline from Alaskan North Slope gas fields to southern waters, near Valdezor Anchorage, where a new terminal would load 3.5 Bcf/d of liquefied gas on to tankers

destined for Asia. The price of the project ranges from $45 billion to $65 billion.

3.2.9 South America

South America has recently emerged as an important market for LNG with the potentialfor future growth as the region seeks to become more economically developed andthereby increasing its energy requirements.


30/44


Brazil currently has two regasification terminals, one in Pecem that has a regasificationcapacity of 0.25 Bcf/d and one in Guanabara Bay that was only recently completed has acapacity of 0.5 Bcf/d. These plants are owned by Petrobras and the purpose of these

projects is to provide fuel for power generation. In late 2013 a third LNG plant isscheduled to be in service. The Bahia terminal, located in the Bay of All Saints, will havea capacity of 0.5 Bcf/d. This terminal is also owned by Petrobras.

Argentina is also stepping up its ability to import LNG to sustain its rapid economicgrowth. It currently has one plant in operation called Bahia Blanca that has a capacity of0.4 Bcf/d. Argentina will more than double its LNG import capacity once a second plantcomes on stream in June. This plant called Escobar, has a capacity of 0.5 Bcf/d. Aproposal is in the works to build a third terminal in partnership with LNG exporter Qatarthat could allow even bigger purchases of the fuel in about two years. This plant, knownhas Golfo San Matias has a proposed capacity of 0.7 Bcf/d.

Chile has also recently added the ability to import LNG by constructing two importterminals, the Quintero facility and the Mejillones facility. Quintero has a regasificationcapacity of 0.35 Bcf/d while Mejillones has a regasification capacity of 0.2 Bcf/d.


31/44


4 Canadas LNG Export Opportunity

This section examines the reasons why Canadian producers might want to participate inthe LNG export market given Canadas large resource potential and growing

unconventional gas production, geographical proximity to Asian markets and theincreasing level of competition that Canadian producers face in the traditional NorthAmerican markets which they currently serve.

4.1 Impetus for Canadas Participation in World LNG Export Market

4.1.2 Large Resource Base Located Near Canadas West Coast

By any measure, western Canadas natural gas resource base is very large. Currently theNational Energy Board estimates the ultimate potential for marketable natural gas in theWestern Canadian Sedimentary basin to be 821 Tcf.

3 Of this some 632 Tcf is remaining

as at the end of 2012. Of these resources, some 531 Tcf are unconventional and thedevelopment of these resources means that Canada has well over 100 years of supplyremaining at current rates of production. A large portion of these unconventional gasresources are found in the Horn River and Montney plays in North Eastern B.C. Thelocation of these resources is shown in Figure 8 below.

Figure 8 - Western Canada Resource Plays

Source: TransCanada

4.1.3 Infusion of Foreign Investment

The emergence of these unconventional gas plays in B.C. has generated worldwideinterest and a number of joint ventures have been announced where South East Asian

3The Ultimate Potential for Unconventional Petroleum from the Montney Formation of British Columbiaand Alberta, National Energy Board, BC Oil & Gas Commission, Alberta Energy Regulator, BritishColumbia Ministry of Natural Gas Development, November 2013, page 6


32/44


investments are being made in the development of these resources. In March 2010,EnCana signed an agreement with Korea Gas Corp. that saw the Asian company buy a 50per cent stake in properties in both the Horn River Basin and Montney shale gas plays inB.C. In August 2010, Penn West Energy Trust entered a gas joint venture with Japans

Mitsubishi Corp to develop properties located in the northeastern corner of BritishColumbia. Malaysia's national oil company Petronas, is investing $1.07 billion to gainaccess to shale gas assets in northeastern B.C. In June 2011, Progress Energy ResourcesCorp. announced it has struck an agreement with Petronas to develop a portion ofProgress Montney shale assets in the foothills of Northeastern B.C.

4 In February 2012,

Encana entered into an agreement with Mitsubishi Corporation that will see the Japanesecompany invest approximately C$2.9 billion for a 40 percent interest in the CutbankRidge Partnership. This Partnership holds about 409,000 net acres of Encana'sundeveloped Montney-formation natural gas lands in the company's Cutbank Ridgeresource play in northeast British Columbia. In the same month, PetroChina Co. signedbinding agreements to buy a stake in a Royal Dutch Shell PLC shale-gas asset in Canada

specifically completing the acquisition of a 20% stake in Shell's 100%-owned land andassets in Groundbirch, northeastern British Columbia. It was reported that the acquisitioncould be worth slightly more than $1 billion. Meanwhile, with regards Alberta-basedunconventional gas plays, in December 2012 Encana entered into a joint venturearrangement with Phoenix Duvernay Gas (Phoenix), a wholly owned subsidiary ofPetroChina, to explore and develop Encana's extensive undeveloped Duvernay landholdings in west-central Alberta. Under the terms of the agreement, Phoenix will gain anon-controlling 49.9% interest in Encana's approximately 445,000 acres in the Duvernayplay for total consideration of C$2.18 billion.

4Subsequent to announcing this joint venture, Progress and Petronas announced PETRONAS Canadiansubsidiary, and Progress entered into an agreement for the purchase by PETRONAS Canada of all ofProgressoutstanding common shares in a the transaction valued at approximately C$5.5 billion. Theacquisition has been granted Canadian Federal Government approval.


33/44


4.1.4 The Need for Market Diversification

To date, Western Canadian gas production only serves North American markets. Of the

total 13.7 Bcf/d of gas produced in Western Canada in 2012, 5.3 Bcf/d was consumed inCanada while the remaining 8.4 Bcf/d was exported to the United States. Traditionally, asshown in Figure 9 below, Western Canadian gas has served markets in California, thePacific Northwest, the U.S. Midwest, the U.S. Northeast and the Western and CentralCanadian markets.

Figure 9 - Selected North American Gas Pipelines & Markets TraditionallyServed by Western Canadian Gas

Just as technology unlocked the shale gas potential in western Canada, it has similarlyunlocked the same potential in a number of other shale basins located elsewhere in North


34/44


America. A number of these plays under more active development are shown on Figure10 and it can be seen that many of them are located in the eastern half of the UnitedStates. While additional infrastructure will need to be built in these plays to connect thegrowing gas supply to the interstate pipeline grid, the predominant direction of flow of

these interstate pipelines is from the traditional producing areas in the south (i.e. GulfCoast and Texas) to the major markets found North in the US Midwest, the Mid-Atlanticand New England regions. This means that as production increases from these emergingUS shale plays, western Canadian production will face more competition for itstraditional markets in the US Midwest, US Northeast and the central Canadian market.As more competition emerges for these traditional markets, it makes sense for westernCanadian producers to explore for new alternative outlets for their natural gas production.

Figure 10 - Selected North American Shale Plays

4.1.5 Proximity to the Rapidly Growing S.E. Asian Gas Markets

The Asian energy market is significantly closer to the west coast of Canada than areEuropean markets, thus it makes sense for western Canadian producers to examinemarket opportunities in Asia and those in South East Asia in particular. With only 8sailing days to Japan and 11 sailing days to China, the west coast ports of Kitimat andPrince Rupert are closer than any other North American port to these markets.

HornRiver

Montney

Eagle Ford

Barnett

Woodford

Fayetteville

Haynesville/ Bossier

Marcellus

Antrim

Utica

Direction of flow ofMajor Pipelines

Markets TraditionallyServed by W.Canadian Gas

Emerging Shale Basins

HornRiver

Montney

Eagle Ford

Barnett

Woodford

Fayetteville


Marcellus

Antrim

Utica

HornRiver

Montney

Eagle Ford

Barnett

Woodford

Fayetteville


Marcellus

Antrim

Utica

Direction of flow ofMajor Pipelines

Markets TraditionallyServed by W.Canadian Gas

Emerging Shale Basins


35/44


4.1.6 Economic Drivers

Currently North American gas prices are depressed due to a combination of weakdemand as the economy continues to recover from the recession of 2008/09 and growing

natural gas supplies from emerging shale plays throughout North America. If traded onan energy equivalent basis, the price of a barrel of oil should be six times that of the priceof an MMbtu of gas. Today, however, the price of natural gas in North America is tradingless than one twentieth of the price of crude oil on an energy equivalent basis. As manyEuropean and Asian natural gas price contracts are more closely tied to oil prices (seesection 1), there exists the potential for western Canadian gas producers to obtain ahigher netback for their production if they are able to access world markets while NorthAmerican prices remain relatively depressed.

Table 9, shows that as a result of the LNG price linkage to oil in South East Asianmarkets, LNG in these markets has sold at a significant premium to AECO pricing.

Table 9 - 2010 Average LNG & AECO Price $C/GJ

AECO Japan LNG ImportAverage

Korea LNG ImportAverage

$3.78 $11.81 $11.07Delta to Aeco $ 8.03 $ 7.29

Source: Information Request Response to NEB by KM LNG in GH-1-2011

For exports of LNG to be economic, the market price for LNG in South East Asian

markets will need to be significantly higher than market pricing associated with naturalgas at AECO/NIT and Spectra Station 2. This is because exporters will incur additionalcosts after gas is delivered to Spectra Station 2 in order to deliver it by pipeline to thecoast where it is then liquefied and finally shipped to Asian Markets. The following tableexpresses these additional costs on an MMbtu Basis.

Table 10 - Additional Costs Expressed on a Per MMBtu Basis

AECO/NIT Spectra Station 2 Base Price

PTP Transportation (i.e. Pipeline to the coast) $0.50 - $1.00

Liquefaction $3.50 - $5.00

Shipping $1.00 - $1.50

Source: Information Request Response to NEB by KM LNG in GH-1-2011

Taking the mid-point of the range of these additional costs shown in table 10 andconverting to $C/GJ yields a total additional cost of $5.93 per GJ in order to transport gasfrom Station 2 to an LNG terminal, then liquefy and ship the LNG to Asia. In 2011, the


36/44


market price for LNG on average in Japan was $14.66/GJ. Netting back this market priceto AECO/NIT Spectra Station 2 using the costs shown above would yield a price of$8.73/GJ. This compares favourably with the average 2011 AECO price of $3.74/GJ.

The data that is discussed above is used to construct Figure 11, which shows in graphicalform the costs that would be incurred to deliver Canadian LNG to South East Asianmarkets. Although there is a large gap between the delivered price of western CanadianLNG and recent LNG prices in Japan, as will be discussed further below, there areconsiderable risks involved in these types of export ventures as increases in NorthAmerican natural gas prices and/or decreases in Asian LNG prices could quickly erasethe price differentials that are seen today between North American and Asian natural gasmarkets. Following the occurrence of the Fukushima Daiichi nuclear disaster in March2011, spot sales of LNG have risen higher than $15/GJ as Japan has sought to attractgreater volumes of LNG to make up for the lost nuclear power generation capacity.However, it remains to be seen how long spot LNG prices will exceed longer-term

contract prices indexed to oil as Japan recovers some of its lost nuclear power capacityand as new sources of LNG are released onto the world market. It is more likely that anew LNG export facility in western Canada would seek long term pricing arrangements,which are traditionally linked to oil prices, rather than rely on the vagaries of the spotmarket which is driven more by gas on gas competition.

Figure 11 - Costs of delivering western Canadian LNG to S.E. Asia $/MMbtu

Another possible cost that has not been factored into the above analysis is the potentialfor government to introduce a special royalty or export levy to target the value added byLNG exports. This type of policy initiative will increase the risks to achieving the returnson investment required for parties to embark on these costly capital ventures and wouldthus act as an impediment to these kind of projects receiving a favourable FID. A policy


37/44


focus that seeks to create a climate that encourages investment in LNG exports will likelyresult in greater benefits. As an additional market outlet would reduce gas on gascompetition in western Canada, then the resource owner would in turn benefit from thehigher royalty revenues arising from any uplift in natural gas prices in the region.

4.2 Potential Canadian West Coast LNG Export Terminals.

There are a number of LNG export terminals proposed for Canadas west coast that are invarious stages of development. While none of the proponents of these proposals has madea final investment decision to proceed, the most advanced of these projects in terms ofobtaining regulatory approvals is KM LNG. This project is equally owned by ApacheCanada and Chevron Canada, with the latter company being the operator. The projectenvisages an LNG terminal to be built at Bish Cove near the port of Kitimat B.C. Theproject would be built in two phases, and after completion of the second phase it wouldhave the capability of exporting some 1.4 Bcf/d of natural gas. The proponents applied to

the National Energy Board for an export licence, which was granted in October 2011.With this licence in hand the project can proceed to secure the commercial arrangementsin order that a final investment decision can be made. The projects first phase would gointo service in 2017 assuming all the necessary regulatory approvals are obtained. TheKM LNG plant will be supported by the Pacific Trail Pipeline which received itsenvironmental approval in 2008.

A somewhat smaller project that is also proposed to be located near the port of Kitimat isthe Douglas Channel Energy Partnership. This project is sponsored by LNG Partners, aprivate equity firm headquartered in Houston, Texas, and HNLP, a limited partnershipestablished for the benefit of the Haisla First Nation. The project envisages two modules

each capable of converting 0.125 Bcf/d of gas to LNG. The proponents are hoping tohave the first module in service as early as 2014. An export licence has been obtainedfrom the NEB.

LNG Canada is a joint venture comprised of Shell Canada Ltd., Korea Gas Corporation(KOGAS), Mitsubishi Corporation and PetroChina Company Limited that is proposing tobuild and operate a liquefied natural gas (LNG) export terminal in Kitimat, BritishColumbia. The project will consist of the construction and operation of natural gastreatment facilities, LNG liquefaction and storage facilities, marine terminal facilities, aninterconnecting cryogenic LNG transfer pipeline, and supporting facilities/infrastructure.It will initially consist of two LNG processing units or trains, each with the capacity to

produce six million tonnes per annum (mtpa) of LNG (equivalent to 0.85 Bcf/d of naturalgas), with an option to expand the project in the future. LNG Canada has selectedTransCanada Corporation to design, build, own and operate Coastal GasLink a 700kilometre pipeline that will connect natural gas from northern British Columbia and theWestern Canadian Sedimentary Basin to the proposed export facility located nearKitimat, BC. LNG Canada has obtained an export licence from the National Energy


38/44


Board (NEB) authorizing the export of up to 24 million tonnes of liquefied natural gas(LNG) per year, for a term of 25 years

Pacific Northwest LNG is owned by PETRONAS, the national oil and gas company of

Malaysia. The proposal consists of an LNG export facility located on Lelu Island in theDistrict of Port Edward located near Prince Rupert. Initially the project will include twotrains, with the ability to expand with the addition of a third train in the future. Theoutput of LNG is expected to be 6 million tonnes per annum per train. On December 16,2013 Pacific Northwest LNG received its export licence for 2.74 Bcf/d from the NEB. Afinal investment decision for the project is expected in late 2014 with first LNG exportsanticipated in 2018. TransCanada has been selected to design, build, own and operate theproposed $5 billion Prince Rupert Gas Transmission pipeline that will transport naturalgas primarily from the North Montney gas-producing region near Fort St. John, B.C. tothe Pacific Northwest LNG export facility.

Prince Rupert LNG is owned by BG Group and has a proposal to build an LNG exportfacility on Ridley Island, BC. The first phase of the project calls for two trains and willexport 14 million tonnes per annum (1.8 Bcf/d equivalent) and phase two will bring anadditional train of 7 million tonnes per annum (0.9 Bcf/d). Prince Rupert LNG receivedan export licence for 2.91 Bcf/d from the NEB on December 16, 2013. BG hasannounced a joint venture pipeline with Spectra Energy that will extend 850 km. fromNortheast BC to Ridley Island near Prince Rupert, BC. The pipeline will be capable oftransporting up to 4.2 billion cubic feet per day of natural gas and will connect with theSpectra Energy system at its Station 2 facilities.

ExxonMobil and Imperial Oil have announced a partnership in WCC LNG. WCC has

indicated interest in obtaining a site near either Kitimat or Prince Rupert, BC and wasrecently granted an export licence from the NEB for 30 million tonnes per annum (4Bcf/d). No pipeline proposals for the project have been made public as of yet.

Woodfibre LNG is owned by Woodfibre Natural Gas out of Vancouver, BC. It proposesa smaller project out of Squamish, BC for the export of 2.1 million tonnes per annum(0.27 Bcf/d). This project received an export licence in the amount of 0.27 Bcf/d from theNEB on December 16, 2013. Woodfibre has stated that it will be supplied via anexpansion of an existing FortisBC natural gas pipeline.

Aurora LNG is owned by Nexen Inc and INPEX CORPORATION of Japan and hasplans to develop an LNG facility at Grassy-Point, BC. Aurora was awarded this locationby the BC government after submitting an expression of interest along with a number ofother parties. An export licence in the amount of 3.12 Bcf/d has been applied for with theNEB.

In January 2013, Calgary-based AltaGas Ltd. and refiner Idemitsu Kosan Co, Ltd. ofTokyo announced they will form a 50-50 partnership to investigate exporting liquefied


39/44


natural gas (methane) and liquefied petroleum gas (mainly propane) from Canada toAsia. This project was named Triton. AltaGas owns the Pacific Northern Pipeline systemthat is currently in-service and delivers natural gas to the communities of Prince Rupertand Kitimat. The pipeline would supply proposed export facilities that target exports of 2

million tonnes per year of LNG by 2017 and 700,000 tonnes of LPG by 2016. A specificsite for the export facility has not yet been identified.

4.3 Scale of Export Capacity and Canadas Abi li ty to Compete

If these projects were all to proceed as envisaged, then Canada would have a total well inexcess of 10 Bcf/d of LNG export capacity situated on its west coast. Table 6 showed thatby 2018, worldwide liquefaction capacity might reach as much as 84 Bcf/d. Althoughtotal potential Canadian capacity would be small relative to this amount, Canada wouldstill be among the top six or seven world exporters at this level of export capacity with

the ability to effectively compete for a share of the growing LNG market.

Liquefaction plants are typically the most expensive element in an LNG project. Inaddition to substantial capital costs, because 8 10% of gas delivered to the plant is usedto fuel the refrigeration process, operating costs can be high as well. Economies of scalecan be significant and where adjoining plants have shared facilities, unit costs can beeffectively reduced. As there are expected to be cost efficiencies if construction of Phase2 of the Kitimat LNG Terminal begins soon after the commissioning of Phase 1, theproject partners have expressed their desire to construct the second train of the project, asquickly as market conditions allow, thereby adding an additional 0.7 Bcf/d of exportcapacity in order to achieve a total capacity of 1.4 Bcf/d for the project. At this level of

export capacity, Kitimat LNG is comparable in size with many of the newer projectsbeing announced throughout the globe. As described above, Shell and its partners areproposing an even larger export facility than that proposed for the Kitimat LNG project.


40/44


4.4 Market Access & Canadas Natural Gas Production Potential

As noted earlier, Western Canada is blessed with vast unconventional gas reserves, as areother areas of North America. As recently as 2007, 10.4 Bcf/d of western Canadian gaswas exported to the U.S., however this figure has declined to around 8.4 Bcf/d currently,and no recovery is anticipated due the emergence of large amounts of US shale gasproduction. While future declines in US demand for western Canadian supply will bepartly offset by the increase in oil sands natural gas demand and growing natural gas-fired power generation, in order to realize its full resource potential, Canadian producerswill require access to new markets such as those that can be reached through the export ofLNG.

In preparing its most recent outlook of natural gas production, CAPP considered two

market scenarios for Canada, namely (1) a market constrained case and (2) a new marketopportunity case. The most significant difference between the two cases is the latter oneassumes that by 2023, five LNG export trains will be in-service on Canadas west coastwith each train having the capacity to export 5 mtpa of LNG (or 0.7 Bcf/d per train). Case(1) in contrast assumes no LNG exports

Documents

An Overview of the World LNG Market and Canada’s Potential for Exports of LNG