Global LNG Outlook - 一般財団法人 日本エネルギー経...
Transcript of Global LNG Outlook - 一般財団法人 日本エネルギー経...
Global LNG Outlook
Medium and Long Term
Quarter 1 2017
IEEJ:April 2017 © IEEJ2017
Global LNG Outlook - Agenda1. Introduction2. Key Assumptions
A. Oil and Coal PricesB. Demand and SupplyC. Infrastructure
3. Medium Term Outlook to 2020A. Demand TrendsB K LNG I tB. Key LNG ImportersC. LNG Export CapacityD. LNG TradeE Spot and Contract PricesE. Spot and Contract Prices
4. Long Term Outlook – 2020 to 2040A. DemandB. LNG Export Capacityp p yC. Asia Pacific Trade FlowsD. Spot and Contract Prices
5. Wrap UpA. Q & AB. Detailed Model Output
1Global LNG Outlook Medium and Long Term Quarter 1 2017
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Introduction
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IntroductionGlobal LNG Outlook comes from the Nexant Base Case sent out to licensees of Nexant’s World Gas Model (WGM). Licensees ( )receive updates each quarter.
Decisions to invest in new supply and infrastructure are not solely based on economics but political and regulatory issues play an important part – the WGM user decides on supply and infrastructure start up dates – the model does not build capacity.important part the WGM user decides on supply and infrastructure start up dates the model does not build capacity.
Pipeline and LNG contracted flows take priority up to TOP levels. Most contracts expire at end of contractual term but some key ones assumed to be extended under the same terms and conditions e.g. Russia to Germany, Qatar to Japan
WGM solves for spot prices – they are not an assumption or input – based on the marginal cost of supply, competing prices and market tightness
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World Gas Model - Overview
Raw Outputs Key Summary OutputsDatabase Assumptions
Production flows Regional balances
Raw Outputs Key Summary OutputsDatabase Assumptions
LNG and Regas throughput Country and nodebalances
Production
Pipeline, LNG andStorage
Oil Price
World Gas Model
Contractual flows Inter and intra regional flows
Storage Infrastructure
Contracts: LNG, Pipe & Transport
Carbon Price
Coal Price
(Node and Arc withLP Formulation)
Prices Spot Prices
Weighted average
LNG Routes
Pipeline trade
Consumption
Weighted average import prices
Cost Stacks
Gas Demand by Sector& Country
Consumption
LNG trade
Cost Stacks
Demand Response
Demand Response
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Regional Definitions – IGU
FSUEurope
Asia
North America
AsiaMiddle East
Africa
AsiaPacificSouth
Africa
PacificSouthAmerica
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Key Assumptionsy p
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Oil and Coal PricesOil Prices Coal Prices
120
1401407.0
80
100
120
14 P
RICE
S
80
100
120
4.0
5.0
6.0
2014
Pric
es
2014
Pric
es
40
60
$/bbl
REA
L 20
40
60
2.0
3.0
$/Ton
ne R
eal 2
$/MMB
Tu R
eal
0
20
2005 2010 2015 2020 2025 2030 2035 2040
0
20
0.0
1.0
2005 2010 2015 2020 2025 2030 2035 2040
$Brent Crude Oil West Texas IntermediateJapan Crude Cocktail
Cent App $/mmbtu NW Europe $/mmbtu
Japan $/mmbtu Ave OECD Import $/Tonne
Oil prices are not assumed to rise above $100 a barrel in real terms – the levels seen in 2008 and in the 2011 to 2014 period, in excess of $100 a barrel, are seen as an aberration. Assumed to rise gradually to $85 a barrel by 2023
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2023Coal prices average out at $80 a tonne in longer term
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Demand and Supply
Demande a d Global demand through 2040 reflects a broad consensus view – close to the IEA’s New Policies Scenario and also the
recent BP, GECF and ExxonMobil base scenarios. These all suggest around 1.6% per annum growth in global gas demand between 2015 and 2040. World natural gas consumption growth rises from over 3 5 tscm in 2014 to almost 5 2 tscm in 2040 World natural gas consumption growth rises from over 3.5 tscm in 2014 to almost 5.2 tscm in 2040. Projected growth is strongest in developing countries where gas still has a relatively low share of Total Primary Energy
Supply. This is particularly true of China where growth in gas consumption will be determined by economic growth as well as by switching from other fuels to gas in the energy mix; Average annual growth is fastest in Asia followed by Africa and the Middle East. Demand is weakest in Europe and the FSU where gas already has a large share of the total primary energy share
(TPES) and growth is limited by economic difficulties, improvements in energy efficiency, and a commitment to renewables.
Supply Potential capacity is based largely on proven and probable reserves, although possible reserves are included for North
America, together with assumptions about production profiles and costs. On this basis, there is more than adequate d ti it il bl i f th tl k i d ith t t l tiproduction capacity available in every year of the outlook period without any recourse to speculative reserves.
The World Gas Model schedules production based on lowest cost, taking into account the cost of transport to market, by pipeline or LNG, as well as the cost of production, subject to contractual obligations US production continues to be increasing driven mainly by development of shale gas. Unconventional gas, which p g y y p g g ,
includes coal bed methane as well as shale gas, is also produced in this scenario in Europe, China and other locations. Nevertheless, conventional gas (which includes tight gas) continues to provide the majority of world gas supply
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Global Liquefaction Capacity
Liquefaction Capacity Assumptions Gl b l it i b 50% b t 2015 d 2020que act o Capac ty ssu pt o s Global capacity rises by 50% between 2015 and 2020, as multiple new projects currently under construction enter service. Final investment decisions for these projects were taken between 2009 and 2015, when global energy price outlooks and gas demand projects were generally stronger
1000outlooks and gas demand projects were generally stronger. There is a second wave of projects between 2024 and 2030
and a third wave from 2035 The U.S. is expected to host six projects up to 2020, with
expansions of these projects later in the forecast period700
800
900
expansions of these projects later in the forecast period, plus two new Gulf Coast based projects. Canada will launch three projects, all on the Pacific coast, in the second and third wave. Most Asia Pacific capacity additions are located in Australia
400
500
600
BSCM
Most Asia Pacific capacity additions are located in Australia, although Indonesia, Malaysia, and Papua New Guinea also contribute. The FSU has multiple new sources of LNG, all in Russia. In
the medium term the Yamal LNG venture currently under100
200
300
the medium-term, the Yamal LNG venture currently under construction and an expansion of the existing Sakhalin II venture provide incremental sources of regional supply In Africa, new liquefaction capacity is assumed in Angola,
Cameroon Equatorial Guinea Mozambique and Tanzania
02005 2010 2015 2020 2025 2030 2035 2040
North America Europe AsiaAsia Pacific Latin America FSU Cameroon, Equatorial Guinea, Mozambique and Tanzania,
mainly 2025 on. Offline liquefaction capacity in Egypt is expected to re-enter full service in 2023.
Asia Pacific Latin America FSUAfrica Middle East
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Pipeline Capacity
Inter-Regional Pipeline Import Capacity Inter-Regional Pipeline Export Capacityte eg o a pe e po t Capac ty te eg o a pe e po t Capac ty
700 600
500
600
400
500
300
400
BSCM
200
300
BSCM
100
200
100
200
02005 2010 2015 2020 2025 2030 2035 2040
North America Europe Asia
02005 2010 2015 2020 2025 2030 2035 2040
E A i FSU Af i Middl E t
Main growth in pipeline capacity is out of FSU – Russia, Azerbaijan, Turkmenistan – to Europe and Asia (China)
o t e ca u ope s aAsia Pacific Latin America FSU Europe Asia FSU Africa Middle East
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Middle East also expands out of Iraq and Iran to Europe and Asia (Pakistan)
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Medium Term Outlook to 2020
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Demand Trends to 2020
Demand Growth by Region – 2015 to 2020 Global demand grows by some 300 bscm or just e a d G o t by eg o 0 5 to 0 0 G oba de a d g o s by so e 300 bsc o jusover 8% to 3,806 bscm 100 bscm in China and 20 bscm in India Middle East evenly spread
A i P ifi d i i l b I d i d liMiddle East
Asia Pacific driven mainly by Indonesia, decline in Japan UK and Turkey contribute most to Europe FSU
Africa
Asia
Asia Pacific
Latin America
North America
Europe
Asia
-20 0 20 40 60 80 100 120 140 160
BSCM
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Europe Supply Gap
Change in Europe Supply Demand – 2015 to 2020 Europe supply gap widens by some 75 bscmC a ge u ope Supp y e a d 0 5 to 0 0 u ope supp y gap de s by so e 5 bsc– 20 bscm already happened in 2016 Pipeline imports up 15 bscm – already 10
bscm higher in 2016 LNG imports up by 50 bscm doubling by LNG imports up by 50 bscm – doubling by
2020 compared to 2015 – small rise in 2016Consumption
LNG Imports
Pipeline Imports
Production
-60 -40 -20 0 20 40 60BSCM
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LNG ImportsChange in LNG Imports – 2015 to 2020g p
United KingdomIndia
China
MalaysiaBelgium
Latin AmericaPakistan
FranceIndonesia
United Kingdom
Other EuropeChinese Taipei
PolandSingapore
SpainLNG Bunker Fuel
Malaysia
EgyptMiddle East
ThailandKorea
TurkeyBangladesh
Other Europe
-10 -5 0 5 10 15 20 25 30North America
JapanEgypt
BSCM
China and India growth is key to increase in LNG imports. UK imports partly “re-exported” to continental Europe. Indonesia imports are mainly from “East” to “West”. Start of use of LNG as bunker fuel. Japan imports decline
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LNG Export Capacity
Change in LNG Export Capacity – 2015 to 2020 Terminal Start UpC a ge G po t Capac ty 0 5 to 0 0Australia Pacific LNG CBM Train 1 2016 1Sabine Pass 1 2016 1Gladstone LNG (CSG) T2 2016 2Gorgon 1 2016 2Sabine Pass 2 2016 3
60Sabine Pass 2 2016 3Australia Pacific LNG CBM Train 2 2016 4Gorgon 2 2016 4PFLNG Satu 2016 4Petronas LNG 9 Sdn Bhd (PL9SB) 2016 4
30
40
50
Gorgon 3 2017 2Sabine Pass 3 & 4 2017 2Wheatstone LNG 1 2017 3Sengkang LNG, Sulawesi 2017 4Ichthys 2018 110
20
30
BSCM
yPrelude FLNG 2018 1Wheatstone LNG 2 2018 1Yamal LNG T1 2018 2Cove Point 2018 2Elb I l d 2018 2
-10
0
Elba Island 2018 2Cameron Trains 1&2 2018 3Freeport Phase 1 2018 4Yamal LNG T2 T3 2019 1Corpus Christi Train 1 2019 1
-202016 2017 2018 2019 2020
North America Asia Pacific Latin America FSU Africa Middle EastCorpus Christi Train 2 2019 2Cameron Train 3 2019 3Sabine Pass 5 2019 3Cameroon FLNG 2019 4PFLNG 2 (Rotan FLNG) 2020 1
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PFLNG 2 (Rotan FLNG) 2020 1
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Unutilised LNG Export Capacity
Unutilised LNG Export Capacity – 2015 to 2020 Unutilised capacity largely U ut sed G po t Capac ty 0 5 to 0 0 U u sed capac y a ge ycontractually determined Spot LNG will be shut in if there is not
enough demand Algeria has the option to export by
80 Algeria has the option to export by
LNG or pipeline – is it really unutilised? US reflects uncontracted capacity50
60
70
M
Middle East mostly Oman Other in 2019 and 2020 is the slow
build up of Yamal20
30
40BSC
0
10
20
2015 2016 2017 2018 2019 20202015 2016 2017 2018 2019 2020
North America Australia Other Africa Middle East Other Algeria
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Inter Regional LNG Flows
Key Inter Regional LNG Flows – 2005 to 2020ey te eg o a G o s 005 to 0 0
70
80
70
80
40
50
60
CM 40
50
60
CM
20
30
40
BSC
20
30
40
BSC
0
10
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
0
10
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
AP to AS ME to AS ME to AP AF to EU NA to AP AF to AS ME to EU AF to AP RU to AP NA to EU
Middle East exports more to China, India and Pakistan as volumes diverted away from Asia Pacific. Asia Pacific l l f d A i US l h d t E d A i P ifi
17Global LNG Outlook Medium and Long Term Quarter 1 2017
volumes also feed Asia. US volumes head to Europe and Asia Pacific
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Market Tightness
Market Tightness Indices – 2012 to 2020a et g t ess d ces 0 to 0 0
1 00
1.02
0.96
0.98
1.00
= 1
0.92
0.94
Inde
x 200
5 =
0.86
0.88
0.90
0.86
2012
Q1
2012
Q2
2012
Q3
2012
Q4
2013
Q1
2013
Q2
2013
Q3
2013
Q4
2014
Q1
2014
Q2
2014
Q3
2014
Q4
2015
Q1
2015
Q2
2015
Q3
2015
Q4
2016
Q1
2016
Q2
2016
Q3
2016
Q4
2017
Q1
2017
Q2
2017
Q3
2017
Q4
2018
Q1
2018
Q2
2018
Q3
2018
Q4
2019
Q1
2019
Q2
2019
Q3
2019
Q4
2020
Q1
2020
Q2
2020
Q3
2020
Q4
North America Europe Asia Asia Pacific
Asia markets tighten as demand rises sharply. Europe tightened in 2015 as production declined but market eases as import supply increases. North America tightens as LNG exports rise. Asia Pacific eases again in 2017
North America Europe Asia Asia Pacific
18Global LNG Outlook Medium and Long Term Quarter 1 2017
as more LNG export capacity comes on
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Spot and Contract Prices
Spot and Contract Prices – 2012 to 2020Spot a d Co t act ces 0 to 0 0
18
20
12
14
16
U
6
8
10
$/MMB
TU
0
2
4
2012 Q1
2012 Q3
2013 Q1
2013 Q3
2014 Q1
2014 Q3
2015 Q1
2015 Q3
2016 Q1
2016 Q3
2017 Q1
2017 Q3
2018 Q1
2018 Q3
2019 Q1
2019 Q3
2020 Q1
2020 Q3
Henry Hub NBP Japan Spot Average LNG Q: Japan Average Pipe Q: China East
Even though Europe and Asia Pacific markets are becoming more supply long, spot prices remain flat – rising cost of supply and rising competing prices offset les tight market. Gap opens up between spot and contract
Henry Hub NBP Japan Spot Average_LNG_Q: Japan Average_Pipe_Q: China East
19Global LNG Outlook Medium and Long Term Quarter 1 2017
prices in Japan as oil prices rise
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Netback Prices to Henry Hub
Netback Prices – 2012 to 2020etbac ces 0 to 0 0
1416
81012
MBTU
0246$/M
M
-20
2012 Q1
2012 Q3
2013 Q1
2013 Q3
2014 Q1
2014 Q3
2015 Q1
2015 Q3
2016 Q1
2016 Q3
2017 Q1
2017 Q3
2018 Q1
2018 Q3
2019 Q1
2019 Q3
2020 Q1
2020 Q3
Henry Hub Netback from Japan Spot (Full) Netback from Japan Spot (Marginal) Netback from Japan Contract (Full)
Netback from Japan is higher than Henry Hub on a marginal basis. From end 2018 the netback from average Japan LNG contracts is higher than Henry Hub as oil prices rise
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Long Term Outlookg
2020 to 20402020 to 2040
21
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Demand Trends to 2040
Demand Growth by Region – 2015 to 2040 Asia demonstrates high growth supported by e a d G o t by eg o 0 5 to 0 0
Middle East
s a de o s a es g g o suppo ed bypopulation increases, greater wealth, rural electrification schemes, and gas’ rising share of national primary energy mixes. Middle East demand also rises as oil producers
Latin America
FSU
Africa Middle East demand also rises as oil producers
seek alternate fuel sources to increase the volumes of petroleum available for export. Rising North American gas consumption is
t d b i d titi l i d
Asia
Asia Pacific
Latin America supported by growing and competitively-priced indigenous gas availability. European demand shows some recovery, but
not to the extent of historic highs. Policies
100 0 100 200 300 400 500 600 700
North America
Europe aimed at improving energy efficiency and boosting the share of renewable energy sources will help contain growth. Recovery is partly attributable to the fact that demand was
-100 0 100 200 300 400 500 600 700
BSCM
2015-2020 2020-2030 2030-2040
so poor between 2011 and 2014; recovery is the only way forward.
2015 2020 2020 2030 2030 2040
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Supply Trends to 2040
Supply Growth by Region – 2015 to 2040 With the exception of Europe, all regions Supp y G o t by eg o 0 5 to 0 0 e e cep o o u ope, a eg o sshow production increases under the Base Case. Global gas production growth is dominated by unconventional gas output gains.Middle East gains. The Middle East records the largest gains
in absolute terms, buoyed by robust Iranian and Qatari output S b t ti l N th A i i tL ti A i
FSU
Africa
Substantial North American gains support its broadening pipeline gas and LNG export base. Projected growth in regions like Africa, the Asia
Asia Pacific
Latin America
FSU, and Asia Pacific is largely export-driven. Production growth in Asia, Latin America,
and the Middle East is almost exclusively 200 100 0 100 200 300 400 500
North America
Europe
yfor domestic use. Against the backdrop of recovering
European gas consumption, the region’s declining output renders Europe
-200 -100 0 100 200 300 400 500BSCM
2015-2020 2020-2030 2030-2040 declining output renders Europe increasingly dependent on natural gas imports.
23Global LNG Outlook Medium and Long Term Quarter 1 2017
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LNG Imports to 2040
LNG Imports by Region – 2005 to 2040 Asia’s increasing importance as an LNG G po ts by eg o 005 to 0 0 s a s c eas g po a ce as a Gimporter reinforces the region’s significance as an LNG demand centre. The start-up of new regasification capacity, and the increasing utilization of existing facilities,
900increasing utilization of existing facilities, drives gains in Asian countries like Bangladesh, China, India, and Pakistan. Europe’s LNG imports rise as sources of
supply are diversified and compensates for500600700800
M supply are diversified and compensates for declining domestic production, but its long-standing position as the world’s second-largest LNG demand centre is superseded by Asia200
300400500
BSCM
Asia. Middle Eastern throughput increases as new
terminals are commissioned in the Persian Gulf, and some existing importers continue to
0100200
2005 2010 2015 2020 2025 2030 2035 2040ramp up deliveries. As a region, Latin America’s throughput level
remains fairly consistent for most of the forecast period after 2018, although the line-
North America Europe Asia Asia Pacific
Latin America FSU Africa Middle East p gup of countries importing LNG changes. The rise of several smaller regional LNG
importers (e.g., Jamaica, Panama, and Uruguay) helps compensate for Brazil’s
24Global LNG Outlook Medium and Long Term
Uruguay) helps compensate for Brazil s reduced requirements in the 2020s.
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LNG Exports to 2040
LNG Exports by Region – 2005 to 2040 Post 2020 capacity and throughput rise in G po ts by eg o 005 to 0 0 os 0 0 capac y a d oug pu seline until 2030, when the market stars to tighten. North American throughput rises from
virtually zero in 2015 to over 90 bscm by9001,000
virtually zero in 2015 to over 90 bscm by 2030 and continues to rise. This suggests that U.S. buyers will exercise
their rights to take cargoes even if Henry H b NBP A i t i diff ti l d500
600700800
CM Hub-NBP-Asian spot price differentials do not fully cover lifting costs. There is a rapid increase in Asia Pacific
throughput due primarily to the ramp-up of 200300400500
BSC
new Australian liquefaction facilities. New capacity in Indonesia, Malaysia, and Papua New Guinea also contribute. African throughput rises rapidly to reflect
0100
2005 2010 2015 2020 2025 2030 2035 2040g p p y
the addition of new capacity, especially in East Africa, and the restoration of offline Egyptian capacity. There is also a rise in FSU throughput to
North America Europe Asia
Asia Pacific Latin America FSUThere is also a rise in FSU throughput to reflect the Yamal LNG start-up, the Sakhalin II expansion, and the addition of greenfield Far East liquefaction capacity.
Africa Middle East Total LNG Capacity
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Unutilised LNG Export Capacity
Unutilised LNG Export Capacity – 2015 to 2040 After 2020 unutilised capacity declines, U ut sed G po t Capac ty 0 5 to 0 0 e 0 0 u u sed capac y dec es,although there is greater “slack” in North America plants and less in Australia –driven by contracts but also by the less competitive US gas as Henry Hub prices
140competitive US gas as Henry Hub prices rise As more plants come online in 2030 “slack”
rises again principally in North America but rising demand quickly reduces this prior to
100
120
M rising demand quickly reduces this prior to the third wave of capacity growth. Post 2035 as there are fewer contracts, the
“slack” is primarily determined on titi d40
60
80
BSCM
competitiveness grounds
0
20
40
02015 2020 2025 2030 2035 2040
North America Australia Other Africa Middle East Other Algeria
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LNG Contracts to 2040
LNG TOP Levels – 2011/12 to 2040/41 Point to Point – contracts withG O e e s 0 / to 0 0/ Point to Point contracts with destination clauses Portfolio import – import terminal
has receipt obligation but supplied 800900
from anywhere Portfolio export – export terminal
has deliver y obligation but can be d li d h Th l l f500
600700800
delivered anywhere. The level of portfolio export in chart is total portfolio export TOP less portfolio import TOP200
300400500
BSCM
import TOP Market appears over contracted
through 2020 – some contracts will therefore undertake-100
0100
However, contracts may have more flexibility and lower TOP as part of renegotiations than thoughtPoint to Point TOP Portfolio Import TOP
P tf li E t TOP U t t dPortfolio Export TOP Uncontracted
27Global LNG Outlook Medium and Long Term Quarter 1 2017
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Asia Pacific Trade Flows to 2040
Asia Pacific Imports and Exports – 2005 to 2040 The Asia Pacific both imports and s a ac c po ts a d po ts 005 to 0 0 e s a ac c bo po s a dexports LNG from/to other regions. The Asia Pacific also imports small volumes of Asian pipeline gas. The region’s current LNG imports are200
250
The region s current LNG imports are chiefly sourced from the Middle East, but this changes dramatically over the forecast period. Middl E t LNG i t
100
150
CM Middle Eastern LNG imports are displaced by deliveries from North America, new African LNG projects, and eventually, flows from expanded
d t i R i ’
0
50BSC
and new ventures in Russia’s advantageously-located Far East. Current inter-regional Asia Pacific
pipeline receipts more than double -100
-50
2005 2010 2015 2020 2025 2030 2035 2040
after 2030, when additional flows from Myanmar (Asia) commence. Inter-regional Asia Pacific natural gas
exports chiefly comprise Australian
Pipeline Imports from Asia LNG imports from N America
LNG imports from Latin America LNG imports from FSU
LNG Imports from Africa LNG imports from ME exports chiefly comprise Australian LNG flows to Asia. These grow significantly over the forecast period. The Asian market may help
underwrite future expansions of
LNG Imports from Africa LNG imports from ME
LNG Imports from Other Sources LNG Exports to Asia
28Global LNG Outlook Medium and Long Term
underwrite future expansions of Australasian LNG export capacity.
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Japan LNG Imports to 2040
Japan LNG Imports – 2005 to 2040Japa G po ts 005 to 0 0
140NorwayPeruIndonesia WestAustralia EastA li W
100
120 Australia WestUSA North EastUSA LouisianaUSA South WestCanada WestEquatorial Guinea
60
80
BSCM
YemenUAEQatarOmanNigeriaEgypt
20
40EgyptAngolaAlgeriaRussia Far EastTrinidad and TobagoPNGMalaysia Borneo
02005 2010 2015 2020 2025 2030 2035 2040
Malaysia BorneoIndonesia EastBrunei DarussalamAustralia NorthUSA AlaskaContracted
Japan heavily contracted through 2020, even some undertakes on contracts. As Qatar contracts fall away, Australia and USA fill the gap. USA especially later in the period. Less from traditional
Indonesia and Malaysia suppliers.
29Global LNG Outlook Medium and Long Term
y pp Demand levels out at 100 bscm – more optimistic than IEA – just under 75 mtpa
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Korea LNG Imports to 2040
Korea LNG Imports – 2005 to 2040o ea G po ts 005 to 0 0
60NorwayPeruAustralia EastAustralia West
40
50USA LouisianaUSA South WestCanada WestEquatorial GuineaYemenUAE
20
30
BSCM
UAEQatarOmanNigeriaEgyptAngolaAl i
10
20 AlgeriaRussia Far EastTrinidad and TobagoPNGMalaysia BorneoIndonesia East
02005 2010 2015 2020 2025 2030 2035 2040
Brunei DarussalamAustralia NorthContracted
Demand expected to recover over time from current lows – consistent with IEA As contracts fall away Russia takes bigger share of market, with PNG supply also Assumes most contracts not renewed but if they were even with different volumes and pricing then supply patterns
30Global LNG Outlook Medium and Long Term
Assumes most contracts not renewed, but if they were even with different volumes and pricing then supply patterns would change
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Spot and Contract Prices
Spot and Contract Prices – 2010 to 2040Spot a d Co t act ces 0 0 to 0 0
18
12
14
16
MBTU
6
8
10
Real
2014
$/MM
0
2
4
02010 2015 2020 2025 2030 2035 2040
Henry Hub NBP Japan Spot Average_LNG: Japan Average_Pipe: China East
Long term contract prices in Japan and China steady at $12 per MMBTU at $85 oil. There is a large gap between spot and contract prices in 2020 which narrows over time as the market tightens and more expensive gas is required to satisfy demand. HH levels
31Global LNG Outlook Medium and Long Term Quarter 1 2017
p g p g q yout as around $4 per MMBTU
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Netback Prices to Henry Hub
Netback Prices – 2012 to 2040etbac ces 0 to 0 0
12
14
8
10
12
TU
4
6
8
$/MMB
T
0
2
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
Henry Hub Netback from Japan Spot (Full)Netback from Japan Spot (Marginal) Netback from Japan Contract (Full)
Netback to HH from Japan contract more than covers the full cost of delivery at oil prices over $70 a barrel. The netback from Japan Spot covers the full cost around 2030
32Global LNG Outlook Medium and Long Term Quarter 1 2017
netback from Japan Spot covers the full cost around 2030.
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The Changing European Gas Market
Quarter 1 2017
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The Changing European Gas Market - Agenda
1 Introduction1. Introduction2. Industrial Structure3. European Gas Pricingp g4. Removing Destination Clauses5. TPA in LNG Receiving Terminals
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Introduction
35
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IntroductionTwo part presentation – Changing European Gas Market and Global LNG Outlookp p g g p
Changing European Gas Market – Requested Scope
1. Impacts of market liberalization to industrial structure in Europe (merger to gas & power company, market oligopoly by a limited number of large companies, etc)
2. How natural gas price is determined in in sub-regions of Europe (oil price link in continental countries, hub link in UK or Belgium, etc)
3. Responses of market players to the EU's decision of free destination, such as Qatar's acquisition and utilization of receiving capacity in European market.
4. Actual implementation and operation of third party access of LNG receiving terminals in Europe (we understand that some of new LNG receiving terminals are exempted from TPA regulation).e G ece g te a s a e e e pted o egu at o )
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Industrial Structure
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Industrial StructureImpacts of market liberalization to industrial structure in Europe (merger to gas & power company, market oligopoly by a limitedp p ( g g p p y g p y ynumber of large companies, etc)
The old model saw large producers selling gas to merchant gas transmission companies who then sold on the gas to LDCs who were the main sellers to end users. In some countries the gas transmission company also owned the LDCs e.g. British Gas in thewere the main sellers to end users. In some countries the gas transmission company also owned the LDCs e.g. British Gas in the UK market.
Market liberalisation has led, along with privatisation, to essentially 4 groups of companies:1 P d d t f dit1. Producers and exporters of gas as a commodity2. Suppliers and traders of wholesale and retail gas3. Generation, regasification and storage asset owners4. Network owners and operators – transmission and distribution
A number of companies are involved in more than one element of the chain – a few in all of the first three.
Companies also move into other commodities, especially electricity, wholesaling and retailing both gas and electricity. In addition network owners and operators, such as National Grid in the UK, cover both electricity and gas networks. What network owners and operators generally cannot do is to become involved in the commodity side of the business wholesaling and retailing of gas.
Network operators, however, are often also owners of regasification assets in particular and storage assets and sometimes generations assets.
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Industrial Structure – British Gas Case Study• After privatisation in 1986 British Gas retained its monopoly of transportation and wholesale and retail supply in the UK market, p p y p pp y
as well as gas storage assets• As the market moved to full liberalisation British Gas divided itself into 3 separate entities, eventually as fully stock market listed
companies:• Transco – covering transmission, distribution and storage assetsg , g• Centrica – wholesale and retail supply plus the Morecambe Bay gas field• BG Group – all exploration and production plus all other international assets – transmission and distribution
• Transco was bought by National Grid – the electricity transmission operator• Centrica expanded internationally and into more upstream production power generation and gas storage – buying the RoughCentrica expanded internationally and into more upstream production, power generation and gas storage buying the Rough
gas storage facility from Dynegy, who had previously bought it from Transco. Centrica also almost invested in nuclear power in the UK
• BG Group developed international LNG business comprising liquefaction, regasification, shipping and portfolio trading• National Grid developed the Isle of Grain regasification facility, separated the distribution network into 8 businesses and sold off p g y, p
4 – recently sold 2 more• BG Group recently bought by Shell
• Many European companies followed similar restructuring and unbundling although some remain wholly or partly state owned.a y u opea co pa es o o ed s a est uctu g a d u bu d g a t oug so e e a o y o pa t y state o ed• The main unbundling is splitting the network operations from the wholesale and retail supply – the infrastructure versus the
commodity
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European Gas Pricingp g
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European Gas PricingHow natural gas price is determined in in sub-regions of Europe (oil price link in continental countries, hub link in UK or Belgium, g p g p ( p getc)?
IGU Wholesale Price Survey has been monitoring prices and price formation mechanisms since 2005
European gas pricing has gone through a transformation in last 10 years
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Europe Wholesale Price Formation – 2005 to 2015
80%
90%
100%
50%
60%
70%
80%
20%
30%
40%
50%
0%
10%
2005 2007 2009 2010 2012 2013 2014 2015
OPE GOG BIM NET RCS RSP RBC NP
Continued rise in GOG – 15% in 2005 to 64% in 2015 at expense of OPE
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Europe Regional Wholesale Price Formation – 2005 to 2015
Northwest Europe Central Europe
100% 100%
Northwest Europe Central Europe
60%70%80%90%
60%70%80%90%
20%30%40%50%
20%30%40%50%
0%10%
2005 2007 2009 2010 2012 2013 2014 20150%
10%
2005 2007 2009 2010 2012 2013 2014 2015
OPE GOG BIM NET RCS RSP RBC NPOPE GOG BIM NET RCS RSP RBC NP OPE GOG BIM NET RCS RSP RBC NP
GOG dominates in Northwest Europe with a 92% share in 2015Largest share at 56% in Central Europe
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Largest share at 56% in Central Europe.
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Europe Regional Wholesale Price Formation – 2005 to 2015
Mediterranean Southeast EuropeMediterranean Southeast Europe
100% 100%
60%70%80%90%
60%70%80%90%
20%30%40%50%
20%30%40%50%
0%10%
2005 2007 2009 2010 2012 2013 2014 20150%
10%
2005 2007 2009 2010 2012 2013 2014 2015
OPE GOG BIM NET RCS RSP RBC NP OPE GOG BIM NET RCS RSP RBC NP
Elsewhere GOG shares are smaller – some 32% in Mediterranean (principally in Italy)Almost non-existent in Southeast Europe.
OPE d i t till i M dit S i d T k d h S th t E ith th RCS t i R i
44
OPE dominates still in Mediterranean – Spain and Turkey, and shares Southeast Europe with the RCS category in Romania.
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Europe Regional Wholesale Price Formation 2015
Scandinavia & Baltics
Southeast Europe
Central Europe
Mediterranean
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Northwest Europe
OPE GOG BIM NET RCS RSP RBC NP
Snapshot of 2015Scandinavia and Baltics has some GOG
2016 ill b t i M t d t h f th t GOG
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2016 survey will be out in May – expected to show further move to GOG
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Removing Destination Clausesg
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Removing Destination ClausesResponses of market players to the EU's decision of free destination, such as Qatar's acquisition and utilization of receiving p p y q gcapacity in European market.
In the EU, destination clauses that prevent onward sales within the EU are considered 'hardcore' restrictions of competition and prohibited under the EU competition rules. Alternative mechanisms, such as profit-sharing mechanisms (PSMs) have beenprohibited under the EU competition rules. Alternative mechanisms, such as profit sharing mechanisms (PSMs) have been permitted where the LNG is sold on a delivery ex ship (DES) basis.
Destination clauses were removed for pipeline contracts more than 10 years ago when, following legal proceedings by the EU, the gas producers agreed to remove themgas producers agreed to remove them.
The enforcement of destination clauses in DES contracts, especially by Algeria to Spain, prompted the rise in the re-export market.
Qatar (as QP) really only holds actually capacity in South Hook which it owns and at Zeebrugge – a 20 year contract. It sells LNG to Edison who have the capacity at Rovigo and to PGNIG in Poland and also to Spain and France on contracts. The buyers of Qatar LNG at these plants will be the capacity holders.
Qatar also sells LNG on a spot basis into the European market, and in terms of the way it uses South Hook in the UK is that apart from a contract with Centrica – which doesn’t actually require LNG to be delivered as they can source it at the NBP – they self contract into the UK market, bringing cargoes in and selling the regasified gas on a daily, weekly or monthly basis.
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TPA in LNG Receiving Terminalsg
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TPA in LNG Receiving TerminalsActual implementation and operation of third party access of LNG receiving terminals in Europe (we understand that some of new p p p y g p (LNG receiving terminals are exempted from TPA regulation).
There are currently 25 large-scale LNG import terminals in Europe. Of these, 23 are in EU countries (and therefore subject to EU regulation), two are in Turkey (which is a candidate for EU membership), 22 are land-based import terminals, and three are floatingregulation), two are in Turkey (which is a candidate for EU membership), 22 are land based import terminals, and three are floating storage and regasification units (FSRUs).
The Third Gas Directive anticipates a system of regulated third-party access to LNG receiving terminals, and requires LNG terminals in the EU to provide transparent and nondiscriminatory access arrangements Developers of new import facilities andterminals in the EU to provide transparent and nondiscriminatory access arrangements. Developers of new import facilities and existing import facilities for which new capacity is being developed may obtain an exemption to such TPA requirements from the national regulator if the project satisfies certain criteria. So far, exemptions to the TPA regime have been granted to six of the EU’s operating LNG regasification terminals: three in the United Kingdom (Grain LNG, Dragon LNG and South Hook LNG), one in France (Dunkerque), one in Italy (Rovigo) and one in the Netherlands (Gate).
The conditions and tariffs of third-party access (TPA) to regulated LNG terminals must be published by terminal operators, as well as approved by the national regulator.
Where a TPA exemption has been granted, the owner of the LNG terminal can negotiate contracts directly with its primary shippers/customers; however, the national regulator monitors anti-hoarding mechanisms, and ensures that shippers have access to a sufficiently transparent secondary market.
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TPA in LNG Receiving Terminals
TPA exempt terminals tightly clustered in Northwest Europe – all are TPA exempt apart from Zeebrugge – the oldest terminal
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Rovigo is on Italy east coast
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TPA in LNG Receiving TerminalsTPA exempt terminals are all in or close to the key trading markets and hubs.p y g
Notable that 2 recent terminals – in Poland and Lithuania are not TPA exempt.
In the UK market, the LNG terminals were regarded as being similar to the beach terminals where gas was brought ashore from the North Sea. UK is the key trading market along with Netherlands.
In Spain in contrast the terminals are much older and would probably not have been eligible for TPA exemption but Spain is aIn Spain in contrast, the terminals are much older and would probably not have been eligible for TPA exemption but Spain is arelatively isolated market with no real liquid trading hub, although there are multiple terminals.
In the TPA regulated terminals usually plenty of primary capacity is available, but in the TPA exempt terminals the primary capacity is often all booked e g in South Hook in UK an affiliate of the owners has booked all the capacity but there is a strong secondaryis often all booked e.g in South Hook in UK an affiliate of the owners has booked all the capacity but there is a strong secondary capacity market.
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Wrap Upp p
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Wrap Up
Q & A
Model Detail
53Global LNG Outlook Medium and Long Term Quarter 1 2017
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World Gas Model
Overview
Mike Fulwood
February 2017
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World Gas Model - OverviewWGM is supplied with a comprehensive database on gas production, LNG and pipeline infrastructure, trade routes as well as long pp p g p p p gterm contracts, storage facilities and demand projections
Key outputs include spot and contract prices, production and consumption, trade flows and infrastructure utilisation
WGM is an excel-based linear programme, with an optimiser add-in, and can be run on a standalone laptopp g , p , p p
WGM can be accessed by clients in a number of ways:
Licensed and installed on client’s own computers, with quarterly updates from NexantLicensed and installed on client s own computers, with quarterly updates from Nexant Customised scenarios of client’s choosing Intensive scenario weeks Subscribe to quarterly World Gas Analytics Service
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WGM – Inputs and Outputs
Raw Outputs Key Summary OutputsDatabase Assumptions
Production flows Regional balances
Raw Outputs Key Summary OutputsDatabase Assumptions
LNG and Regas throughput Country and nodebalances
Production
Pipeline, LNG andStorage
Oil Price
World Gas Model
Contractual flows Inter and intra regional flows
Storage Infrastructure
Contracts: LNG, Pipe & Transport
Carbon Price
Coal Price
(Node and Arc withLP Formulation)
Prices Spot Prices
Weighted average
LNG Routes
Pipeline trade
Consumption
Weighted average import prices
Cost Stacks
Gas Demand by Sector& Country
Consumption
LNG trade
Cost Stacks
Demand Response
Demand Response
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Functioning of the World Gas Model
First Selected Year
KEY
First Selected Year
Visual Basic
Import Data forCurrent Year
Return Result to WGM
イメージを表示できません。メモリ不足のためにイメージを開くことができないか、イメージが破損している可能性があります。コンピュータを再起動して再度ファイルを開いてください。それでも赤い x が表示される場合は、イメージを削除して挿入してください。
Excel File
イメージを表示できません。メモリ不足のためにイメージを開くことができないか、イメージが破損している可能性があります。コンピュータを再起動して再度ファイルを開いてください。それでも赤い x が表示される場合は、イメージを削除して挿入してください。
Database
イメージを表示できません。メモリ不足のためにイメージを開くことができないか、イメージが破損している可能性があります。コンピュータを再起動して再度ファイルを開いてください。それでも赤い x が表示される場合は、イメージを削除して挿入してください。
WGM
Call What’s Best
Visual Basic
Excel File
What’s Best!O i i
Copy raw quarterly results for current year to light blue tabs
All selected years optimised
YesNo Optimiser
Create Output FileNext Select Year
Yes No
F db k th t iOption to create output file later
Stop
Output file
Feedback the spot prices
St
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Stop
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Unique Feature – Modelling Spot PricesSpot prices, either at hubs or for spot LNG cargoes, are considered to be a function of three factors:p p p g The marginal cost of supply; Prices of competing fuels; and The tightness of the market which includes local production capacity as well as the availability of pipeline and LNG supply.
The level of market tightness for the particular market determines whether the forecast spot price is closer to the marginal cost of supply or to the competing price.
The tighter is the market then the closer the spot price is to the competing price. In a less tight market the spot price might be expected to be closer to the marginal cost of supply.
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Appendix: WGM Specificationspp p
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WGM – What it does?
WGM is supplied with a comprehensive database on gas production, LNG and pipeline infrastructure, trade routes as well as long term contracts, storage facilities and demand
WGM is based on excel and with the system configuration below:• Win 7 (8 GB RAM)/ Win 10 (16 GB RAM) [64 bit systems)• Office 2010 / Office 13 [64 bit versions]• Linear Programming solver – What’s Best (64 bit)Run time: We have optimised run time to under 10 min for a fullwell as long term contracts, storage facilities and demand
projection. All data needed to run the model is supplied by Nexant and users are free to add or overwrite the supplied assumptions to construct scenarios Database
System i t
Run time: We have optimised run time to under 10 min for a full scenario run
assumptions to construct scenarios of interest to their organisations.
Database requirement and run time
WGM
WGM runs on a stand‐alone computer or laptop. The Excel interface allows users
to modify inputs easily and incorporate outputs
SupportOutputs
Key outputs include spot and contract prices, production and consumption, trade flows and infrastructure utilisationGlobal Consumption to modify inputs easily and incorporate outputs
into other internal programs and systems.
Nexant provides comprehensive support services including initial installation and training regular updates of data and
Spot Price differentialsEuropean pipeline imports
initial installation and training, regular updates of data and technical support. All users benefit from a continuous programme of model development and enhancements.
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Optimisation – Linear ProgrammingA linear programme is an optimisation problem consisting of:p g p p g input assumptions constraints Physical variables such as production and flows by pipeline and LNG are constrained by capacity assumptions. Gas and LNG contracts are modelled using constraints to represent contract volume termsGas and LNG contracts are modelled using constraints to represent contract volume terms.
Objective: Objective function is to minimise costs including energy price assumptions and infrastructure and production LRMCs (which include both capex and opex)
Solving this linear programme leads to forecasts of: gas production at each source of supply (e g gas fields) gas production at each source of supply (e.g. gas fields) flows spot prices
Conceptually, the WGM LP is expressed as a network: Nodes - containing the demand, production, storage, LNG and regas assumption Arcs - representing connections between the nodes (pipelines and shipping routes and also used to model LNG and pipeline contracts)
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System Requirements
H d S ftHardware SoftwareStandalone computer with 8 GB RAMrecommended
Windows 7 (64-bit)recommended
Office 2010 64-bit (English language version please)
What's Best! Add in with the 64 bit Extended Base What s Best! Add-in with the 64-bit Extended Base Version as minimum
Some clients have moved to Windows 10 and Office 2013. The model runs fine in this environment but as Windows 10 takes up a lot more RAM than Windows 7, 16 GB of RAM would be recommended
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Accessing the World Gas Model
WGAS is a subscription program that provides coherent forecasts for global, regional and national supply/demand d i f t l d LNG
The World Gas Model (WGM) is available to the clients to use under license on their own systems. The clients benefit from the database containing detailed Information about and prices for natural gas and LNG.from the database containing detailed Information about production, infrastructure and contracts, continuous support and global coverage in WGM.
LicensingWGAS
SubscriptiLicensing Subscription
Products
Clients can consult with Nexant to create
Bespoke
S i
Scenario Week
In a Scenario Week – we sit with the client in their office running the scenarios and
iti iti i l ti idi th d tClients can consult with Nexant to createbespoke scenarios starting with our base case,and then changing key assumptions to generatealternative scenarios and sensitivities.
Scenarios sensitivities in real time, providing the data, results and analysis from each scenario.
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Appendix: Spot Price Backcastingpp p g
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North America (Henry Hub)
16
12
14
16
8
10
12
MMBT
U
2
4
6$M
0
2
6 Q1
6 Q3
7 Q1
7 Q3
8 Q1
8 Q3
9 Q1
9 Q3
0 Q1
0 Q3
Q1
Q3
2 Q1
2 Q3
3 Q1
3 Q3
4 Q1
4 Q3
5 Q1
5 Q3
6 Q1
6 Q3
2006
2006
2007
2007
2008
2008
2009
2009
2010
2010
2011
2011
2012
2012
2013
2013
2014
2014
2015
2015
2016
2016
Calculated Spot Actual Spot
Tracks changes pretty well – 2011 and 2012 actual less than calculated
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Europe Netherlands
141618
101214
MBTU
468SM
M
02
Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3
2006
Q
2006
Q
2007
Q
2007
Q
2008
Q
2008
Q
2009
Q
2009
Q
2010
Q
2010
Q
2011
Q
2011
Q
2012
Q
2012
Q
2013
Q
2013
Q
2014
Q
2014
Q
2015
Q
2015
Q
2016
Q
2016
Q
Calculated Spot Actual Spot
Tracks changes pretty well – since 2011 calculated level generally less than actual level
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Asia (China – Shanghai)
25
20
25
15
MMBT
U
5
10SM
0
Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3
2006
Q
2006
Q
2007
Q
2007
Q
2008
Q
2008
Q
2009
Q
2009
Q
2010
Q
2010
Q
2011
Q
2011
Q
2012
Q
2012
Q
2013
Q
2013
Q
2014
Q
2014
Q
2015
Q
2015
Q
2016
Q
2016
Q
Calculated Spot Actual Spot
Tracks changes pretty well – since 2011 calculated level slightly less than actual levelChina spot LNG a pretty thin market though
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Asia Pacific (Japan)
20
25
15
MNTU
5
10%M
0
Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3
2006
2006
2007
2007
2008
2008
2009
2009
2010
2010
2011
2011
2012
2012
2013
2013
2014
2014
2015
2015
2016
2016
Calculated Spot Actual Spot
Tracks changes pretty well since 2008 (spot market thin before that) – but post-Fukushima calculated level generally slightly less than actual level
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