OXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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LNG Markets in Transition
The Great reconfiguration
Anne-Sophie Corbeau
Jonathan SternOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

IEEJ：October 2016 © IEEJ2016

The authors

 OIES and KAPSARC brought together 12 international experts fromthe industry and academia to create this bookAnne-Sophie Corbeau

David Ledesma

Jonathan Stern

Howard Rogers

Ken Koyama

Jim Jensen

Chris Lefevre

Jim Henderson

Sylvie D’Apote

Anouk Honore

Chris Caswell

Brian Songhurst

INTRODUCTIONOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Looking back at the past 2 years• Mid 2014: we started thinking about the LNG book––––

‘Only’ 100 mtpa under construction, including 1 US project
Asia still considered as the bottomless premium market for LNG
Oil prices at ~$100/bbl
Many planned projects ready to take FID

How is the LNG business going to be affected by these changes?
• May 2016: we finalize the book– 150 mtpa to come over 2015-20 (64 mtpa in the US)– Asian LNG demand growth uncertain (additional volumes) (down by

2 percent in 2015), buyers in search of flexibility– Sellers looking at new markets– Oil prices at around $40-50/bbl, gas spot prices at ~$4-6/MMBtu– Who will take FID?

Towards a reconfiguration?
INTRODUCTIONOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Moving away from the “cosy” club

• Multiplication and diversification of players in the liquefaction, shipping andregasification businesses• Aggregators are increasing their role, buyers are going upstream, traders want toparticipate, and new entrants to take market shares (even in Asia)• More companies alliances on the buyer side
INTRODUCTIONOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Developments in the chain
Sabine Pass tolling structure• New companies are coming into
the LNG business, throughout
the whole value chain• These companies bring new
ideas and ways of doing
business that have challenged
the norms of the LNG sector• Changing market structures are
driving changes in LNG
contracts• US projects have adapted the
LNG tolling structure and LNG
business models• FSRUs give fast access to market• FLNG gives options for liquefaction
CHANGING COMMERCIAL STRUCTURES

Where is LNG demand heading?
Regional LNG demand outlooks
700
600

500

mtpa

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400
300
200

100
0

2020
JKT

China/India

2025

2030

Other Asia

2020
LA

ME-Africa

2025

Europe Low

2030

Europe High• Considerable regional uncertainty• Europe will play a balancing role, absorbing unwanted volumes in the low demandcase and letting LNG go to other markets in the high demand case
• Potential upside in the transport sector
DEMANDFocus on Asian LNG demand

Low case

High case450450Vietnam

400

Vietnam400

Bangladesh

350
300

Bangladesh

Pakistan

350

Malaysia

300

Pakistan
Malaysia

Indonesia

250

Thailand200

Singapore

150

India
China

100

TaiwanSouth Korea

50

Mtpa

Mtpa

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Indonesia

250

Thailand200

Singapore

150

India
China

100

TaiwanSouth Korea

50

Japan
0
2010

2015

2020

2025

2030

0
2010

Japan
2015

2020

2025

• Asia will remain the largest LNG importing region• Individual factors can result in very different outlooks for Asian countries

DEMAND2030

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Key drivers for Asian demand
Production/Pipeline
Supply Decline

Energy Mix
Uncertainty (Policy)

SingaporeJapan
Indonesia

TaiwanThailandIndia
Malaysia
Vietnam
Pakistan
Bangladesh

•
•
•
•

China

Potential for LNG demand growth – in aggregate significant.
Needs a change in marketing strategy – credit risks higher in many cases.
But current low prices help establish markets
And FRSUs can float away if bills not paid.
Poor
DEMAND

Investment/Price
FrameworkMature Asian markets
140

Japan

Spot and other Short Term Supply

120

Identified Short Term Contracts
Existing Medium and & Long Term Contracts US

100

Existing Medium & Long Term Contracts NonUS
Historic Medium & Long Term Contracts
80
Demand (Historical)

Bcma

Japan:•
Huge uncertainty range driven by a) pace andextent of nuclear re-start and b) achievement ofenergy efficiency policy.
South Korea:•
Future LNG demand growth muted bygovernment policy to limit LNG in power sector,
hoping to offset coal GHG’s by renewables andnuclear.
Taiwan:•
LNG the beneficiary of government commitment
to phase out nuclear in the 2020s while
containing growth of coal.
•
Future power demand growth also a large
uncertainty.

Fast Nuclear restart, high demand
60

Fast Nuclear restart, low demand
Partial Nuclear Restart, High demand

40

Partial Nuclear Restart, Low Demand
Slow Nuclear Restart, High deman d

20

Slow Nuclear Restart, Low Demand
0
2010

2015

2020

2025

2030

60

35

South Korea

Taiwan30

50

Spot and other Short Term Supply

25

Identified Short Term Contracts

40
Contestable Demand

Existing Medium and & Long Term
Contracts - US
Existing Medium & Long Term Contracts
Non-US

15

Spot and other Short Term Supply
Identified Short Term Contracts

Bcma

20

Bcma

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30

Existing Medium and & Long Term Contracts - US
Existing Medium & Long Term Contracts Non-US
Historic Medi um & Long Term Contracts

Historic Medium & Long Term Contracts

LNG Demand (Low)
LNG Demand (High)LNG Demand (High)1020

LNG Demand (Low)

5

10

0
2010

2015

2020

2025

2030

0
2010

DEMAND

2015

2020

2025

2030

China600

600

Low Case

High Case
500

500

400

400
LNG Imports

LNG Imports

Pipeline Imports - West Siberia

Pipeline Imports - West Siberia

Pipeline Imports - East Siberia

Pipeline Imports - East Siberia

Bcm/y

Bcm/y

300

200

300

Pipeline Imports - Turkmensitan & Central Asia

Pipeline Imports - Turkmensitan & Central Asia

Pipeline Imports - Myanmar

Pipeline Imports - Myanmar

Domestic Production

Domestic Production

Demand

100

200

0

0

2000

2005

2010

2015

2020

2025

2030

2000
120

China:•
Gas Demand growth subject to:
–
–

•
•
•

Demand

100

2015

2020

2025

2030

80
Spot Transactions
Short Term Contracts
Existing M & LT Contracts - JCC

60

Historic M & LT Contract Imports

High Demand
Low Demand

40

20

0
2010

DEMAND2010

LNG Demand

Changed patterns in the ‘New Normal’.
Success of policy to displace coal with gas inpower generation, space heating in Industry – 100
bcma in 5 years ?

Growth of domestic production dependent on
shale gas success.
Scale of Central Asian imports expandable
and timing and number of Russian pipeline
projects uncertain.
LNG Imports therefore lie in a wide range: 75
to 105 bcma by 2030.

2005

100

Bcm/y

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2015

2020

2025

2030

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The role of LNG in Europe
 Europe is acting as the swing market for LNG and as a result, the region is expected

to help absorb the LNG surplus coming on to the market in the second half of the2010s and early 2020s
 But the region is facing major uncertainties:– The future role of natural gas in the whole energy system is in question,
primarily as a result of greater governmental support for renewables– The region will face a decline of its indigenous (conventional) production.
Unconventional gas and biogas production will increase but it will have little
impact on the major decline. In a low energy price environment, it is difficult toenvisage more optimistic scenarios Despite low demand growth, declining indigenous production means that Europe
will have to increase its gas imports, but how much and from which sources is
unclear– In 2015, most of the gas imported arrived in the form of pipeline gas (88% of
total demand) with a predominant role of Russia (33% of total demand), themain competitor to LNG“Europe” = EU28 + Albania, Bosnia and Herzegovina, Macedonia, Norway, Serbia, Switzerland, and Turkey

DEMANDOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Latin America: substantial potential for
additional LNG imports•••

Energy demand (and in particular power demand) is still growing and thedevelopment of local resources is taking more time than expected
Natural gas has a role to play as a clean and efficient complementary sourceof firm energy to hydropower and intermittent renewable sources, but
flexibility of supply will be an important element
In 2030, the region is expected to need 37 – 103 bcm of LNG (uncertainties
about the pace of development of local resources and great variability of LNG
demand in Brazil)
DEMANDOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Middle East and Africa: more than aniche market?
• Currently a very small market representing 10 mtpa
• Both regions are overall exporters, but intraregional pipeline trade has
proven difficult to put in place or expand• Middle East
– Many countries facing gas shortages and struggle to develop new generation of gas
fields– Currently four countries importing, more looking at LNG imports– Most ME countries have low wholesale gas prices, which are increasing• Africa– Egypt started importing in 2015, but scale and duration highly depends on future
domestic production– At least eight other countries are looking at importing LNG for variable durations– Most of them opt for FSRUs (except for Morocco)– Many issues related to financing, need to provide regulatory certainty to prospective
sellers, affordability and payment issues

DEMANDOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Prospects for LNG use in transport• Low oil prices make the financial case harder• The environmental case is primarily driven by legislation.
• The benefits from reduced GHGs are less than other emissions
though methane slip can be reduced/eliminated through technicalenhancements• Initial prospects are stronger in marine than in road apart from China– Already established for LNG tankers– Greater scale (1 ferry ≅ 1,300 buses)– Legislation in place– “LNG ready” a no regrets step for some new build– Easier to establish refuelling facilities– Norway has demonstrated what is possible• Could be a significant market by 2030
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The Main Markets

N America

Europe+ Regulatory(mainly marine)+ Supply surplus(availability andprice)+ LNG storage+ Active andInnovative equipment
supply chain+ Many new entrants+ Good prospects in railand off-road+ Regulatory (road andmarine)+ Price advantage+ Potential supply surplus+ LNG terminals & storage+ Number of active andinnovative players- Limited LNG infrastructure- Variable taxation- Consumer resistance- Restricted vehicle range

LNG IN TRANSPORT- Variable taxation- Consumer resistance- Restricted vehicle range

China+ Regulatory(concern over pollution)+ Price advantage (though
can be eroded)+ Existing LNG supply chain(with surplus capacity)+ Extensive LNG vehicle
availability and experience- Impact of state price control- Regional pricing differentials- Fragmented haulage
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Who will provide new LNG supply?
• Well documented upsurge in output underway (+150 mtpa)• Some declines in existing producers• Qatar a continuing constant• Economics of new projects very challenged – will there be new FIDs
in the US, Australia, Russia, East Africa before 2020?
• Canada has missed the short-term window – no output until well into
2020s
• Opportunities for new producers are politically as well as commerciallydifficult• Portfolio aggregation can help to support some projects• Brownfield expansion in politically stable areas the most likely sourceof new LNG post 2020

SUPPLY

Australia LNG
Location of Australian LNG projects

Outlook for Australian LNG

Sunrise FLNG

100

Western Market
Northern Market

Ichthys90

Eastern Market

Bonaparte Basin
BrowseFLNG

80Bonaparte FLNG

Scarborough FLNG
PreludeFLNG

70

DARWIN
DarwinLNG
Bonaparte
Gas Pipeline

BrowseBasin

North West Shelf LNG

mtpa

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60

Gorgon LNG

Pluto
LNG

Wheatstone LNG

NORTHERNTERRITORY

Telfer Pipeline

50

Amadeus Basin to
Darwin Pipeline

QUEENSLANDSouth West Queensland Pipeline (SWQP)

Canning Basin
Pibara Pipeline
System (PPS)

Carnarvon
Basin

40

Dampier to
Bunbury
Pipeline

30

Queensland Gas Pipeline (QGP)

WESTERN
AUSTRALIA

10

SOUTH
AUSTRALIA
Kalgoorlie to Kambalda
Pipeline

Perth
Basin

0

Kambalda to Esperence
Pipeline

Wallumbilla
Hub

2014

2015

2016

2017

2018

2019

Arrow LNG

Moomba to Adelaide
Pipeline System (MAPS)

Pluto

QC LNG

IchthysPreludeAPLNG

GorgonVictorian Transmission System (VTS)

Gas basins

SUPPLYSYDNEYCANBERRA
Eastern Gas Pipeline (EGP)

GLNG• Australia ramp up well underway, despite low prices• Some delays, but set toovertake Qatar by 2019
• Cash costs low, especially in
Asia

Roma to Brisbane Pipeline(RBP)

NSW Basins

VICTORIA

MELBOURNE

Wheatstone

BRISBANE

VictorianInterconnector(VNI)

ADELAIDE

DarwinSuratBowen
Basin

NEW
SOUTH
WALES

2020

AP LNG T1-2
Expansion at all projects

Moomba to Sydney
Pipeline (MSP)

Cooper Basin

Sea Gas Pipeline

NWS

GLNG T1-2
GLADSTONE

Queensland to
South Australia /New South Wales
link (QSN)

PERTH

2013

QC LNG T1-2

Amadeus Basin
Goldfields Gas Pipeline(GGP)

Midwest Pipeline
(MWP)

20

Carpentaria
Pipeline

Gas processing

LNG Liquefaction Plant Existing

Onshore natural gas pipelines

LNG Liquefaction Plant Under Construction

Offshore natural gas pipelines

LNG Liquefaction Plant Planned

Otway
Basin

Bass
Basin

Gippsland
Basin
Tasmanian Gas Pipeline

TASMANIA• Potential for new projects very
limited, despite falling costs• Some brownfield expansion
possible in 2020s• An extra 20mt of capacity by2025?

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North American LNG
Summary of North American LNG projects
RegionTotal number ofprojects

Total capacity
Including underconstruction(mtpa)

Number of
projects underconstruction

Capacity (mtpa)

US Gulf and East
Coasts

35

364

5

64

Oregon

2

16.6

0

0

Alaska

1

18

0

0

British Columbia

18

301

0

0

Eastern Canada

5

52

0

0

United States

Canada• US project output ramping up towards end of decade, but impact still
being felt in global LNG market• Is there any incentive for new project development, or could current
projects default?
• Will there be any Canadian LNG projects within the next decade?
SUPPLY

Russian LNG
Outlook for Russian LNG
90
80
70
60

mtpa

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50
40
30
20
10
0
2015

2020

2025

Sakhalin 2

Yamal LNG

Baltic LNG

Sakhalin 2 Expansion

Vladivostok LNG

Far East LNG

Arctic LNG

Pechora LNG

Shtokman2030• Yamal LNG to start up in 2017, fully online by 2020
• Sakhalin 2 expansion logical but (politically difficult so) and not before 2021
• Baltic LNG – 5-10 mt or a limited project for bunker market and Kaliningrad?
• Other projects significantly delayed
SUPPLYEastern Africa LNG
Scenarios for Eastern Africa LNG developments
35
30
25
mtpa

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20

15
10
5
0

Mozambique HighTanzania High

Mozambique Low
Tanzania Low• Prospects for Eastern Africa undermined by low prices• Regulatory, legislative and fiscal issues also major hurdles• Tanzania could fail altogether• Mozambique reserves very large, but timing of output in doubt
SUPPLYOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Other LNG supply developments
Key existing producers to note
• North Africa• Qatar• Other Middle East
• Indonesia/Malaysia• PNG
Potential new producers• Iran• East Mediterranean• Latin America• Where can projects be madecommercially viable?
SUPPLY

No. of
Sites

Total
Trains

Total
CapacityFirst
Output2015
Sales% change
2015/2014)

mt

year

mt

%

Atlantic Basin
Algeria
Angola (stopped)
Egypt (stopped)
Equatorial Guinea
Libya (stopped)
Nigeria
NorwayTrinidad & Tobago
Sub-Total

5
1
2
1
1
3
1
3
17

17
1
3
1
4
6
1
4
37

28.5
5.2
12.2
3.7
3.2
21.8
4.3
15.5
94.4

1972
2013
2005
2007
1970
1999
2007
1999

12.1

19.5
4.3
11.8
51.4

-4%
-100%
-100%
7%
na
2%
20%
-10%
-2%

Middle East
Abu Dhabi
Oman
Qatar
Yemen (stopped)
Sub-Total

1
1
12
1
15

3
3
14
2
22

5.8
10.7
77.0
6.7
100.2

1977
2000
1999
2009

5.7
7.6
78.4
1.5
93.2

-7%
-2%
3%
-76%
-3%

Pacific Basin
Australia
BruneiUSA
Indonesia
Malaysia
PNG
Peru
RussiaSub-Total

7
1
1
3
4
1
1
1
19

10
5
1
11
9
2
1
2
41

36.6
7.1
0.4
31.9
24.2
6.9
4.5
9.6
121.2

1989
1973
1969
1977
1983
2014
2010
2009

29.5
6.5
0.3
18.0
25.0
7.2
3.6
10.6
100.6

25%
6%
7%
4%
1%
111%
-11%
0%
12%

Total

51

100

315.8

245.2

3%

3.7

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Economics of FLNG
• Configurations• Inshore/pipeline

Courtesy Höegh LNG• Offshore/subsea

Courtesy Shell International Ptd.

FLNG

• Costs & Schedule• Major Energy Companies– $1700-3200/tpa including
subsea, complete project($5.9-11.2/tpa)• Leasing Companies– $600 quoted for vessel only($2.1/MMBtu) – add
contingency for first of akind
– Similar to US Gulf Coast
Plants – good opportunity
for high cost locations asinshore alternative– OPEX: $1.3/MMbtu– Schedule 32-66 months

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Prospects for FLNG

• Prospects– In addition to 7 inconstruction - 17 mtpa
– 17 in study phase –55 mtpa– If 50% of theseproceed then 34 mtpa
– 18% of 241 mtpa
global production in2014 – significant
market share

FLNG• Conclusions– First FLNG in production late 2016
– More in construction – some on
speculative basis – new builds andconversions– Offshore and inshore configurations– Option to lease reducing capitaloutlay– Opportunity to deliver lower costplants (similar to US Gulf Coast) tohigh cost areas e.g. Australia, Eastern
Africa, Canada in under 3 years –enabling earlier and higher revenue
stream– More major offshore leasing
companies looking to enter themarket increasing competition

The evolution of spot and short-term
LNG trade
Spot and short-term LNG trade, 1999-2015
100%

80
70

80%

60
50

60%

40
40%

mtpa

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30
20

20%

10

0%

0

Algeria
NorwayAustralia
Peru

Egypt
Qatar
Malaysia
Trinidad

E. Guinea
Oman
Indonesia
OthersNigeria
Yemen
RussiaTrade (right)

Source: forthcoming ‘LNG markets in transition: the great reconfiguration’ (OIES/KAPSARC).

• Spot and short-term LNG trade represented 28% of global LNG

trade in 2015, down from 29% in 2014
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Drivers behind the growth of
spot and short-term LNG trade• Supply side developments– Uncommitted or ‘spare’ LNG capacity– Ramp-up volumes– Volumes initially committed to a market, but released and redirected– Portfolio LNG (without secondary sales)• Demand side developments– Demand shocks leading to more flexibility on TOP– Expansion of LNG import capacity more rapidly than liquefaction– The impact of liberalization in Europe and the U.S.
• The creation of liquid hubs
• TPA to infrastructure (Europe)• End of final destination clauses (Europe)– Change in the nature of buyers from government monopolies orutilities in OECD countries to smaller players, IPPs and traders

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The buyers’ dilemma• Future gas demand over the next 10-20 years is uncertain– Economic growth– Competitiveness of gas against coal
– Development of renewables and– Evolution of nuclear policy• Liberalisation processes in Asia means higher competition on themarkets• Difficulties to pass through LNG costs to end-users in periods ofhigh(er) prices• How to commit for 20 years?

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Adapting to markets uncertainties
JERA’s business plan, February 2016

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Further growth of spot LNG trade Further growth of spot and short-term LNG trade will besupported by the following elements:– Uncommitted LNG– (Ramp-up volumes)– Lack of contracts extension and renegotiation at lower volumes– Portfolio LNG– The role of Qatar and US LNG

CONTRACTS AND FLEXIBILITY

Towards 43% of total LNG trade by 2020
Evolution of spot and short-term LNG trade
200

50%
40%

150

mtpa

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30%
100
20%
50

10%

0

Low case

0%High case

Share of LNG Trade (low)Share of LNG Trade (high)Source: Forthcoming ‘LNG markets in transition: the great reconfiguration’ (OIES/KAPSARC).

• Potentially some upside in the short term depending on ramp-up

volumes
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Implications for long-term contracts• Existing LT contracts:–

Increased pressure on price and flexibility terms–

This could be exacerbated by discontinuity between term and spot
prices, financial distress of buyers• LT contracts supporting new LNG plants:–

Moving without the support of LT contracts seems a bridge too far at
this stage–

For that to happen, we would need•Spot LNG trade to become the norm•

Reliable price benchmarks•

Support/agreement from banks•

And a substantial drop in LNG costs for project sponsors to take that risk

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Tackling a $2bn/y inefficiency

Optimising shipping• If we were to optimize shipping based on the shortest route, we

could save $2bn/y• Unrealistic? Margins are low! It is time for collaboration…
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Regional gas and LNG prices

 Europe and North America price gas mainly at hubs; (most of) Asia

still prices LNG in relation to oil
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Price formation mechanisms
which could replace JCC

 Henry Hub or European (NBP/TTF) hub prices
 Asian spot price Index (eg JKM, RIM, Argus, JOE): too few cargos (atleast currently) on which to base long term contracts
 Prices at an Asian hub or hubs
 Average Japanese/Korean LNG import prices – JLC/KLC `Hybrid pricing’ – a mixture of all of these + JCC/oil+ electricity +……

Which of these mechanisms best reflects gas
supply/demand conditions in Asian countries
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Comparing oil-indexed LNG to
US HH-indexed LNG
US LNG export cost* to Asia at different Henry Hub
prices compared with different JCC prices

 US LNG exports looked very profitable in Asia at $100/bbl oil, but at$2.50/MMbtu Henry Hub will struggle to cover full costs below $50/bbl oil
PRICINGJapanese LNG spot import prices
Japanese LNG spot prices, 2009-2016
25

20$/MMBtu

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15

10

5

0

NBP Cal Month MA Av

JKM

JOE spot

 In 2016, JKM and NBP converged in the first half of the year
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A Future Asian LNG Hub:Singapore, Shanghai or Tokyo?

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Establishing a liquid hub takes timeand commitment
Indices derived for
LT Contracts
Liquid Forward Curve
Develops
Futures Exchange
Non – Physical Players enter

10 + years ?

OTC Brokered Trading
Balancing Rules & Standardised Trading
Contracts
Price Discovery and Disclosure

Bi-Lateral Trades
Third Party Access to Pipelines/Regas Terminals
Based on Experience in US, UK and Continental Europe:•••

This could take 10 years in Asia
It requires the commitment of government, suppliers and system operators
An over-supplied market with strong competition accelerates the process
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A Singapore Hub?
POTENTIAL DISADVANTAGES:• A market of 6mt – although with plans to expand significantly – may not

be large enough to set prices for Asia. (LNG Imports in 2015 2.2 mt)• Location may be too far from the major Asian LNG markets to provide acompelling price reference; but close enough to SE Asian countries
ADVANTAGES:• First mover – current location of 24 companies operating in the Asian

LNG space• Sufficiently neutral politically that others may accept it as an index

A virtual hub for SE Asia? Unlikely to develop enough depth andliquidity to be a reference for the big Asian LNG markets

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Shanghai: a hub or a city gate?
ADVANTAGES:• The location where domestic and international (LNG and pipeline) gas

supplies come together in Asia’s biggest (and most rapidly expanding)gas market• Result of a price reform with a compelling market logic (but lacks
market flexibility)• TPA in principle to pipelines and LNG terminals

POTENTIAL DISADVANTAGES:• Lack of transparency of supply and demand ie not genuinely “market-

driven”• Overly dominated by three Chinese state-owned companies (and hence

the Chinese government)

Shanghai is currently a “city gate benchmark” rather than a
hub price, but it could evolve over time
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The Exchanges: how much progress?
SINGAPORE:• 2015 the SGX LNG Index Group creates the `Sling’ price, first derivative

contract reported in early 2016

SHANGHAI:• Petroleum Exchange trades small volumes of LNG but• is overly dominated by Chinese market players and hence not a neutral

body for market trading

TOKYO:• TOCOM and Ginga Energy – created the JOE LNG forward platform in2014 to become a futures market• Has traded very little LNG since creation (first contract August 2015)

Progress still very much in early stages
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METI’s May 2016 LNG Strategy• `Develop an internationally accepted trading hub…by the early 2020s’
which will..strengthen the power to negotiate prices for the nation asa whole• `important for both parties to permit anonymous information
disclosure to an agreed PRA from the perspective of developing
better indices• LNG trading contracts using price indices will be positively taken into
account for evaluation of national interest by JBIC, NEXI and
JOGMEC• Rules concerning TPA to LNG terminals and information disclosure to
be formulated (consider best practice in Europe)

METI can facilitate but it will require Japanese market players tomake this happen!

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Asian markets do not need to adopt
the same price mechanism• SINGAPORE: an LNG trading location which develops a regional

price for South East Asia
• CHINA: a Shanghai citygate benchmark price reflecting

domestic/international gas prices, and prices of competing fuels(fuel oil and LPG)
• JAPAN: a hybrid/spot JCC/JKM/HH/NBP price developed bycompetition which could evolve into a hub

These prices will have a relationship with each other andin time will create a “messy transition” to a converged
Asian composite price; meanwhile expansion of spot
pricing will put continued pressure on JCC-based longterm contracts, especially if oil prices increase
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Conclusions on pricing• North America and Europe price gas at hubs
• Asian LNG prices are still largely JCC-based but this has diminishingmarket logic• By early 2016, important status quo players (eg JERA) begin to

openly speak about the need for transition to market prices – recalls
start of the transition in Europe• May 2016: METI LNG Strategy makes transition to hub pricing`official policy’• Asian hubs may evolve over the next decade and this could beaccelerated by:– Over-supply of LNG up to 2020 (and perhaps up to mid 2020s)– Increasing spread between JCC and spot prices (if oil prices increasebeyond $50/bbl)
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Why a reconfiguration?
• The supply/demand balance will look significantly different in 5

years from now and there is great uncertainty about the future
supply• There is increasing pressure from the buyer’s side for more

flexibility and a change in price formation, from oil indexation
to hub indexation, to address:– Uncertainties around future gas demand growth– Market liberalization in Asia
– Maintaining gas competitiveness versus coal

• Long-term contracts under threat from flexible LNG supply– Share of spot trade to increase from 28% in 2015 to about 43%
by 2020

CONCLUSIONSINTROWhen will markets rebalance?
LNG supply and capacity outlook
600

?

500
400

mtpa

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Supply gap?

300

200
100

1000 mtpa
plannedNorth America
RussiaEastern Africa
Qatar
Others

0

2014

2015

2016

2017

2018

2019

2020

2025

Existing - likely stable

Existing - uncertain evolution

Existing - not operational

Under construction

Possible capacity additions• Project sponsors will take FID depending on their views on the timing of market

rebalancing, future prices and cost reduction

CONCLUSIONS

Difficult for projects to take FID
in this price environment
Global gas price environment, 2008-2016

25
20$/MMBtu

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15

10
5

0

HH

NBP

Japan

Brent (3,3)

Source: Bloomberg, EIA.

• Pressure on pricing mechanisms, notably in Asia
• Pressure on costs
CONCLUSIONS

Full cost of U.S.
LNG to Asia (HH @$2/MMBtu)

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Which projects will move forward?
• The cost competitive projects– Brownfield expansion••

Notably Qatar, the low cost LNG producer
Utilisation of existing under utilized LNG capacity in Egypt, Trinidad and Oman

– Projects with strategic involvement from buyers– FLNG– Liquid-rich projects• And those left behind– Uncompetitive fiscal framework, uncertain regulation, potentially rapidly

growing domestic demand, politically unstable

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Price war in Europe?

Russian pipeline gas

U.S. LNG builds up

Price
war

Asian demand growth

ME LNG is displaced to
the Atlantic :Europe + LA
Asia Pacific LNG capacity increase+72 mtpa over 2015-20

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So where does this leave us?
• Companies realizing that they have to adapt to the new market

environment• Companies have to change the way they operate– What do we mean by collaboration?
– Cost is king; innovative and cost-competitive projects could proceed– Lots of potential in new markets … as long as LNG is ‘affordable’ andcompetitive– Changes in pricing formation are coming, but there is resistance– Existing projects can accept more flexible contract structure, while new
projects will require some form of LT commitments unless conditions arefundamentally different– Contract sanctity?

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Thank you for your attention

Contact :report@tky.ieej.or.jp