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Challenges to JCC Pricing in
Asian LNG Markets
Professor Jonathan Stern
Chairman and Senior Research Fellow
Natural Gas Research Programme

IEEJ SEMINAR, TOKYO, MARCH 18, 2014

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OIES Natural Gas Research Programme
WE ARE:•A gas research programme at a Recognised Independent
Research Centre of Oxford University, specialising in fossil fuelresearch•Probably the only European academic research group focussed
on natural gas.

WE PRODUCE: independent research on national and international
gas issues
WE ARE FUNDED BY: sponsorship by 20 companies andgovernments in gas producing and consuming countries
WE ARE NOT:
• consultants, sellers of exclusive, high price business reports

In 2013 the Oxford Institute was voted the world’s No.1 Energy
and Resource Policy Think Tank
http://gotothinktank.com/dev1/wp-content/uploads/2014/01/GoToReport2013.pdf
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Published 3rd February 2014 – Free to Download

http://www.oxfordenergy.org/2014/02/challenges-to-jcc-pricing-in-asian-lng-markets-2/

Asia pays very high prices for LNG imports
25
Brent

20
Europe Oil
IndexedContract
estimate:

Asian LNG
Spot

15$/mmbtu

Beforeconcessions
After
concessions(estimate)

Average JapanLNG Price

10
NBP

5
Henry Hub

SOURCE: Platts, EIA, Argus, Own Analysis

Jul-13Jan-13

Jul-12

Jan-12

Jul-11

Jan-11

Jul-10Jan-10Jul-09

Jan-09Jul-08Jan-08

Jul-070
Jan-07OXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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OXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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What’s the Problem?
• Oil price linkage was introduced in the 1970s when
oil was the main competing fuel to natural gas inJapanese power generation• The cost pass-through mechanism allows Japaneseutilities to adjust their gas and power tariffs to end
users by the same percentage as the country’s
average LNG procurement cost movements,
regardless of an individual buyer’s actual purchasecosts• Projects “need oil linked prices” to support new LNG
supplyBut, post-Fukushima, a new mood/new fundamentals;
Japanese utilities begin to make substantial losses

Japan: 10 Largest Power Company Financials – very
big losses!
10,000

5,000
TEPCO

Profit/Loss in Year, US$ Millions

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-

Okinawa
FY
FY
FY
FY
FY
FY
FY
FY
FY
FY
FY
FY
FY
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

-5,000KyushuShikoku

ChugokuKansai-10,000

Hokuriku
Chubu-15,000

TohokuHokkaido-20,000-25,000

Source: http://www5.fepc.or.jp/tok-bin-eng/kensaku.cgi

OXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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What is the main problem related to pricing:is it price level or price formation?

• Is the problem that prices are too high? If so
the problem is price level• Or is the problem that prices no longer haveany market logic? If so the problem is priceformation

Reducing the price level is a short term solution,
but in the longer term only a change in priceformation will solve the current problem

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If the problem is the price level –what could be done?

• Reduce the base price• Reduce the slope• Adjust the “kink points” of the S-curve• Repeat the above as often as required…
What does this achieve: it reduces the level ofthe price, but maintains the JCC mechanism.
But if oil prices continue to rise then constantadjustment is required

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If the problem is price formation – what is
the way to approach the problem?

Reassess the market for gas, what fuels (energies)
compete with natural gas
Assess whether interfuel competition is still operating
and in which part of the market?
• If yes, a mix of oil products/coal/ power base price andindex may work
• If no, then the market will need to move to a spot/hub
gas index eg:– JKM or similar and related to this– Henry NBP (plus liquefaction and transport costs)– A hub price: physical, virtual, located in Asia
The aim of the process is a price which keeps LNG/gas
competitive nationally and globallyOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

IEEJ: March 2014. All Rights Reserved.

China illustrates the differences between JCC,
oil-indexation, alternative fuel and hub pricing
Russia Altai
2020: 02030: 30bcm?
Russia East
2020: ?
2030: 38bcma

Central Asia
China Domestic

2020: 50bcm

2010: 100bcm

2030: 80bcm

2020: 150bcm
2030: 250bcm
Myanmar

Source: BP Statistical Review 2013, Author’s estimates

2020:12bcm

LNG

2030:12bcm

2010: 10bcm
2020: 70bcm
2030: 120bcm• Pipeline imports from Central Asia and Myanmar (and negotiations
with Gazprom) are oil-indexed• LNG prices are JCC-based• Post-2011 price reform aims at hub pricing at Shanghai citygate,based on an average of gas import and alternative fuel pricing

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Price Formation Option 1:
alternative fuel pricing
ADVANTAGES:• Reflect current energy market conditions which can bemonitored over time
• Should never get substantially out of line withcompeting fuels
DISADVANTAGES:• Competitive fuels difficult to agree with sellers• Needs frequent re-calibration as market and fuel mix
evolves.
• May be only a transitional stage to spot/hub prices
Does interfuel competition have a market logic; inwhich countries and which sectors?
If not, the only alternative is supply/demand pricing ofsome sortOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

IEEJ: March 2014. All Rights Reserved.

Price Formation Option 2:
Spot and Futures Pricing
Spot LNG Price Index (eg JKM):•Advantage: reflects current Asian LNG supply/
demand balance•Disadvantages:– too few cargoes (at least currently) on which to base longterm contracts– May reflect global, rather than Asian, market dynamics

Futures Market Pricing (announced by Japanese
government in April 2013) – but this needs a physicalbasis

This would become much more credible if spot andshort term trade increases; liquidity is insufficient on
which to base a futures priceSpot LNG Volumes
Global350

In 2012, Spot LNG Cargoes
Represented 19.5% of Global
LNG Volumes

300

250

'Spot Traded' LNG

BCMA

200

Short Term Contracts

Medium & Long Term Volumes

150

Toal LNG Supply

100

50

2500
2006

2007

2008

2009

2010

2011

2012

Asia

200

150

In 2012, Spot LNG Cargoes
Represented 19.1% of AsianLNG Volumes'Spot Traded' LNG

BCMAOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Short Term Contracts

Medium & Long Term Volumes
100

Toal LNG Supply

50

0
2006

2007

2008

2009

Source: GIIGNL, Author’s Analysis

2010

2011

2012

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Option 3: Henry Hub/NBP-based pricing
ADVANTAGES:•Established hub price mechanism, no suspicion ofmanipulation by Asian stakeholders•Currently lower price than JCC
DISADVANTAGES:•risky if HH prices rise significantly above $6/Mmbtu(and oil price falls)•No Asian market fundamentals

Henry Hub/NBP pricing risks being a short term device
to reduce price level, not a long term solution to theprice formation problem; cold weather in US in Feburary
2014 illustrates how HH prices can increase

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Price Formation Option 4:
Pricing at an Asian Hub
ADVANTAGES:•Provides on-going price reference which can evolvefrom physical trade into a hedging/risk management
reference with a range of durations•Can be a physical or virtual location
PROBLEMS: needs many (all?) market players toagree on:•location – each country wants its own hub•liquidity acceptable as price reference•rules – trading/financial regulation

This will take national/regional agreement and time toestablishOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Uncertainties in Global Dynamics Post 2015
• Asian and particularly Chinese Natural Gas
and LNG demand.
• Continued robustness of US shale gas
production and scale of US LNG exports.
• Scale and pace of non-US LNG export supply(especially Australia, East Africa, Russia,
Canada).
• Shale gas outside North America (post2020/2030?)• Russian strategy for price versus volume forpipeline supply in Europe (and Asia)

Drivers for change

Drivers for Change: LNG Supply 2005 – 2025
(Excluding Possible US & Canadian Projects)

1000

Further East Africa &Other
Tanzania

Unrisked

Mozambique

900

RussiaAustralia

Risked @ 50%

Nigeria

800

Yemen

USA - Kenai

700

Trinidad

Existing & Low Risk

Qatar
Peru

600

Papua New Guinea
Oman

BCMA

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Norway500

Malaysia

Libya
Israel400

IranIndonesia

300

Eq. Guinea
Egypt
Canada200

Cameroon
Brunei
Brazil100

Abu Dhabi
Angola0

Algeria

2004

2009

2014

Source: Waterborne LNG, D. Ledesma, Own Analysis

2019

2024

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Global LNG Fundamentals:
major uncertainties for Asia
• Co-incidence of North American Exports with next
increase of global LNG supply (Australia, East Africa,etc) may lead to a new ‘glut’ or at least a ‘softer’ LNG
market.
• In part this will be fostered by LNG aggregators /portfolio players all targeting (finite) Asian LNG
demand.
• It will also depend on how much Russian pipeline gas
and LNG export capacity is developed and by when
• In addition to the assumed continued robustness of US
production this also depends on growth of Chinesedemand for LNG

120

0

100

80

US LNG Export Projects
with secured off-takeGolden Pass

BCMA

Cameron LNG
Dominion Cove Point60

Lake Charles
Freeport

40

Sabine Pass20

0

120 2010

2015

2020

2025

100
80

Capacity Ownership* Assumes BG Retains 100% of Lake Charles

BCMA

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Note that US LNG
exports are relatively
limited prior to 2019-20.
This is a big
uncertainty for LNG
supplyAggregator
India

60

South Korea
40

Japan

20

0
2010

2015

2020

2025

Sources: Company & Media Reports,
Author’s Assumptions

Russian LNG and Pipeline Gas Export Projects
to Asia are Potentially Important
Shtokman- 15mmtpa in
Phase 1?

Yamal LNG – 16.5mmt
CNPC - 3mmtpa
Negotiations with Europeanand Asian traders

Sakhalin 1 – 5mmt
SODECO – 1mmtpa
Marubeni – 1.25mmtpa
Vitol – 2.75mmtpa

Pechora LNG– 2.6mmtpa ?

Sakhalin 2 – 10mmt
Various Asian buyers expansion agreed

Chayanda
Leningrad LNG– 10mmtpa ?

Kovykta

Source: OIESS-K-V

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38bcmato China?

Gazprom
Novatek

Vladivostok LNG– 10-15mmt

Rosneft

The ending of Gazprom’s monopoly on LNG
exports at the end of 2013 indicated government
support for 3rd party exporters – Rosneft andNovatek are actively competing with Gazprom forcustomers

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The Power of Siberia Pipeline and VLNG
Terminal ~ $80-90bn
Source OIES

Economics of Vladivostok LNG depend on “Power ofSiberia” Pipeline Gas Exports to China

21

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Russian pipeline gas exports could cut
Chinese LNG import requirements by
40 Bcm/year in the 2020s
Source: Henderson and Stern/OIES22

IEEJ: March 2014. All Rights Reserved.

Asian LNG Importers: spot, short term and long term
contracts 2010 - 2025
Japan
30

120

Taiwan25

100
Contestable Demand
Spot Transactions
80

BCMA

Contestable Demand

20

Short Term Contracts

Spot Transactions

BCMA

Existing M & LT Contracts - HH
60

Existing M & LT Contracts - JCC
Historic M & LT Contract Imports

40

Short Term Contracts

15

Existing M & LT Contracts - HH
Existing M & LT Contracts - JCC

LNG Demand

Historic M & LT Contract Imports

10

LNG Demand

20
5

0

2010

2015

2020

2025
0

80

2010

2015

2020

2025

South Korea

70
60

Contestable Demand

BCMA

50

160

Short Term Contracts
40

140

Existing M & LT Contracts - HH
Existing M & LT Contracts - JCC

Contestable Demand

LNG Demand

BCMA

100

10

50

2010

2015

2020

Spot Transactions

80

Short Term Contracts

60

Existing M & LT Contracts - HH

2025

40
35

120

Historic M & LT Contract Imports

20

450

China

Spot Transactions

30

Existing M & LT Contracts - JCC

40

Historic M & LT Contract Imports

India

Contestable Demand20
LNG Demand

Spot Transactions

30

BCMA

OXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

140

Short Term Contracts
25

Existing M & LT Contracts - HH

0
2010

2015

2020

2025

LNG Demand (without Russian
Pipeline)

Existing M & LT Contracts - JCC

20

Historic M & LT Contract Imports

15

LNG Demand

10
5
0
2010

2015

2020

2025

Source: GIIGNL, D. Ledesma, Rogers and Stern 2014

Future Asian LNG Demand and Contracts:
spot, short term and long term
Sources: GIIGNL, Rogers and Stern 2014450
Spot Transactions
400

Short Term Contracts
350
US Sourced - Agrregators
300
BCMA

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US Sourced - Asian Buyers

250

200

Existing LT Contracts - JCC

150

Historic LT Contract Imports

100

LNG Demand50

LNG Demand (without Russian
Pipeline Imports to China)

0
2010

2015

2020

2025

The Asian LNG market could become very competitive in the late
2010s and early 2020s; China is a big uncertainty for LNG demand

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A Future Asian LNG Hub: Singapore, Shanghaior Tokyo?

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Asian LNG Hub – Three Stages of Development ?
Current Situation
End-Users of LNG

Situation Post 2016
End-Users of LNG

Mid-Stream
Incumbent
BlendedImport Price

Incumbentowned LNG
ImportTerminal

Spot LNG
Imports

Mid-Stream
Incumbent
BlendedImport Price

HH plus JCCmargin- indexed
indexed LNG
LNG Contract
Contract

Source: Rogers and Stern/OIESEnd-Users of LNG

Hub-based
price

MidStream
Incumbent
BlendedImport Price

Incumbentowned LNG
ImportTerminal

Spot LNG
Imports
JCC-indexed
LNG Contract

Situation Post 2020?

LNG Import
Terminal with
3rd Party
Access.

Spot
LNG
Imports HH plus
marginindexed
LNG
Contract

JCCindexed
LNG
Contract

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Costs are a major problem for new LNG projects

Source: Deutsche Bank Markets Research, Global LNG, 17 September 2012

Commercial “train wreck” approaching for some Australian projects?

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LNG Plant Cost ($/TPA) by Year of start-up

Average200% increase
2005-2012
Average

Data Courtesy GIIGNL/Wood MacKenzie

Songhurst/OIES: 2014

28

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Recent LNG Costs – High and Low Cost Locations

Data Courtesy of GIGNL, Wood Mackenzie, Published Reports
Songhurst/OIES, 2014

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Possible Areas for Future LNG Cost Reduction• Utilisation of barge-mounted liquefaction plant built in
China or Korea. This cost of this concept has beenquoted at $600-700/TPA including storage• For onshore constructed plants using a morecompetitive process and EPC contractors.
• Bringing in a competitor to GE/Nuovo Pignone (whocurrently have an exclusive supplier position) for
refrigeration compressors and drivers. Other major
vendors include Siemens, Dresser, Rolls Royce fordifferent components• Cooperation between the owners of different projects
in the same area to get better value from the synergies.
This is being applied in Mozambique where Anadarko
and ENI are now planning a joint development.
SOURCE: MAJOR CONCLUSIONS FROM SONGHURST/OIESOXFORD INSTITUTE FOR ENERGY STUDIES Natural Gas Research Programme

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Asian LNG: Scenario1. Contractual Impasse• Buyers continue to complain about JCC pricing but
there is little change in the status quo. No changes
can be agreed in existing contracts.
• Buyers refuse to sign new long term contracts atprices linked to crude oil; producers refuse to go
ahead with new projects on any other price basis,and no new LNG contracts are signed.

• Spot trade increases with US LNG export growth but
the problems of price competitiveness (on average
LNG import prices) mean that Asian LNG trade
stagnates.

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Asian LNG: Scenario 2. Smooth Contractual Transition• New contracts start to be signed with a mix of oil,Henry Hub and NBP prices, with price review clauses
which mandate renegotiation of prices after a numberof years, anticipating the creation of an Asian hub.
• There are challenges to existing contract prices, butrenegotiations result in adjustments which are tolerable
for both buyers and sellers with no fundamental
changes or litigation. Despite losses, Japanese buyers“hang on” until their existing long term contracts begin
to expire/decline.
• Spot trading increases significantly and a hub pricebegins to emerge during the 2010s, initially in
Singapore.
• By the 2020s, larger and more liquid hubs emerge inTokyo and Shanghai and new contracts with buyers inthose countries are priced on this basis.

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Asian LNG: Scenario 3. Contractual Train Wreck• For Japanese LNG buyers losses from existing contracts become
financially untenable and they demand price renegotiations.
• These are resisted by suppliers with new, high cost new projects
coming on stream which need to pay back substantial investments
and feel unable to compromise on the JCC-related prices in theircontracts.

• Litigation ensues with unpredictable results. The processhighlights the need for a “reset” in the commercial framework.
• A several year period of commercial upheaval ensues during
which no new contracts are signed other than with North American
sellers…
• but spot and short term trading continues to increase and as in the
Smooth Commercial Transition scenario, a hub price emerges in
Singapore, followed by larger and more liquid hubs in Tokyo andShanghai and new contracts with buyers in those countries are
priced on this basis.

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Asian LNG: Scenario Conclusions• In all three scenarios, new contracts are signed with North
American sellers on a Henry Hub price basis, but this introducesanother risk for buyers that such prices do not reflect evolving
market fundamentals in the Pacific region.
• We do not believe that `Contractual Impasse’ is a sustainable
scenario but it remains a possible outcome if parties are unable toreach agreement, at least for a few years.
• The `Smooth Contractual Transition’ scenario is clearly the mostdesirable outcome to move from the JCC status quo to hub-based
pricing. However, it depends on maintaining a controllable
financial situation for buyers and sellers.
• The `Contractual Train Wreck’ scenario results from the financial
position of buyers (and/or sellers) becoming untenable. All Asian
LNG stakeholders must clearly be hoping this does not occur but...
• markets where prices have liberalised and hubs have been created– North America, UK and Continental Europe – have had“contractual train wrecks” of varying magnitudes.

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Most Difficult Problems to Resolve• Threat to traditional “relationship culture”
between buyers and sellers• Lack of third party access to pipelines/liquefaction terminals• Dominant (monopoly?) players in all Asian
countries• Potentially greater price volatility• Traditional “security culture” of Asian buyers:– Absolute assurance of demand coverage throughlong term contracts, replaced by greater short
term/spot purchase– Not a problem as long as buyers offer the highest
price, but no reason to offer several $/MMbtu morethan necessary

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Summary of the Problems Facing JCC• JCC is no longer a rational basis for pricing Asian LNG;
threatens competitiveness of economics• Key question is ‘what is the most appropriate basis onwhich to price LNG, which reflects Asian market
fundamentals and is most ‘future-proof’?
• One or more Asian LNG trading hubs are the longer
term solution to prices which reflect market
fundamentals; establishing these hubs create difficult
problems for both buyers and policymakers, especially..
• addressing the challenges of existing Long Term JCC
contracts for high cost projects which have not yet
commenced delivery

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FINAL THOUGHTS• This is likely to be a very difficult and painfultransition which may take at least a decade tocomplete• The solution may be different for different
Asian LNG importing countries• Oil prices will continue to play a role indetermining LNG prices but this will not be acontractual requirement• There is no guarantee that hub-based prices
will always be lower than JCC prices (but withoil prices above $100/bbl this is likely)

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Thank you for your attention
This presentation is based on the following published research:
The Impact of a Globalising Market on Future European Gas Supply
and Pricing: the Importance of Asian Demand and North American
Supply’ Howard Rogers, January 2012,
http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/01/NG_59.pdf
A realistic perspective on Japan’s LNG Demand after Fukushima.
Akira Miyamoto, Chigako Ishiguro, Mitsuhiro Nakamura. June 2012
http://www.oxfordenergy.org/2012/06/a-realistic-perspective-onjapan%E2%80%99s-lng-demand-after-fukushima/
The Pricing of Internationally Traded Gas, Editor Jonathan Stern
OUP/OIES 2012.
Challenges to JCC Pricing in Asian LNG Markets, Howard Rogers &Jonathan Stern, February 2014.
http://www.oxfordenergy.org/2014/02/challenges-to-jcc-pricing-in-asian-lngmarkets-2/
The potential impact on Asian gas markets of Russia’s Eastern Gas
Strategy, James Henderson and Jonathan Stern, February 2014.
http://www.oxfordenergy.org/2014/02/the-potential-impact-on-asia-gasmarkets-of-russias-eastern-gas-strategy/
Contact: report@tky.ieej.or.jp