Report of Special Project 1-A “Catalysing Asia's Energy...

22nd World Gas Conference June 1-5, 2003, Tokyo, Japan

Report of Special Project 1-A

“Catalysing Asia's Energy Future”

Rapport du projet spécial 1-A

“Catalyser un avenir énergétique en Asie”

Editor Kenji Yamaji

Japan

Lead Author Yasumasa Fujii

Japan

Report of Special Project 1-A “Catalysing Asia's Energy Future”

Editor Kenji Yamaji, The University of Tokyo

Lead Author Yasumasa Fujii, The University of Tokyo

Steering Committee

Coordinator Kenji Yamaji, The University of Tokyo

Sub Coordinator Tsutomu Toichi, The Institute of Energy Economics, Japan

Yasumasa Fujii, The University of Tokyo

Members Takashi Okano, The Tokyo Electric Power Company, Incorporated

Akira Ishii, Japan National Oil Corporation

Koji Nagano, Central Research Institute of Electric Power Industry

Tsutomu Oya, Tokyo Gas Co., Ltd.

Atsushi Manago, Osaka Gas Co., Ltd.

Hideo Hasegawa, The Institute of Energy Economics, Japan

Osamu Izawa, Tokyo Gas Co., Ltd.

Kazuki Takahashi, Tokyo Gas Co., Ltd.

Satoshi, Nakamura, Osaka Gas Co., Ltd.

Mitsunari Ogawa, Toho Gas Co., Ltd.

Kazuhiko Satoya, Saibu Gas Co., Ltd.

IGU Advisory Board Members

Chiaki Gomi, TCC Chairman

Rudolf M Ter-Sarkisov, WOC1 Chairman, VNIIGAZ

Frank Heinze, WOC2 Chairman, VNG - Verbundnetz Gas AG

Angel Travesset, WOC3 Chairman, BBG

Carlo Malacarne, WOC4 Chairman, Snam Rete Gas S.p.A.

Joel Gregoire, WOC5 Chairman, Gaz de France

Jaap Roos, WOC6 Chairman, INTERGAS

Bob J. Harris, WOC7 Chairman

Wayne Soper, WOC8 Chairman, Duke Energy

Terence H. Thorn, WOC9 Chairman

Eduardo Zapata, WOC10 Chairman, Metrogas S.A.

Secretariat

Ryo Fukushima, NOC of WGC2003

Koji Okuda, NOC of WGC2003

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TABLE OF CONTENTS

EXECUTIVE SUMMARY 1

RÉSUMÉ (French) 4

1. INTRODUCTION 8

2. MODEL STRUCTURE 11

3. MODEL DATA SETTINGS 38

4. BASE CASE RESULTS 45

5. CONCLUSIONS 63

REFERENCES 65

Appendices

A. Reviews of the natural gas market in Asia 67

B. Storylines on Asia’s Natural Gas Perspectives 111

ii

Unit Conversion Table

Energy Natural gas From

To TOE m3 ft3

t-LNG MJ kCal KWh

TOE 1 1.04x103 3.67x104 7.52x10-1 4.19x104 1x107 1.16x104

Nm3 Nat. Gas 9.62x10-4 1 3.53x10 7.23x10-4 40 9.50x103 11.2

Sft3 Nat. Gas 2.72x10-5 2.83x10-2 1 2.05x10-5 1.14 2.72x102 3.16x10-1

t-LNG 1.33 1.38x103 4.88x104 1 5.57x104 1.33x107 1.54x104

MJ 2.39x10-5 2.48x10-2 8.76x10-1 1.79x10-5 1 2.39x102 2.78x10-1

Kcal 1x10-7 1.04x10-4 3.67x10-3 7.52x10-8 4.19x10-3 1 1.16x10-3

KWh 8.60x10-5 8.97x10-2 3.16 6.48x10-5 3.60 8.60x102 1

1Nm3(dry base): Normal cubic meter at 0°C, 1atm, dry base

1Sft3(dry base): Standard cubic feet at 60°F, 1atm, dry base

Prefixes 106 million, mega, M

109 Billion, Milliard, giga, G

1012 Trillion, tera, T

1015 Quadrillion, peta, P

1018 Quintillion, exa, E

CO2 1t-C = 3.67 t-CO2

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Executive Summary

ES-1 Introduction

This report aims to describe the future of the energy infrastructure, especially the natural gas

infrastructure in Asia as a part of the Special Project, “Global Energy Scenarios (GES)”, for the

Triennium Work Programme 2000-2003 by the International Gas Union, and then eventually to analyze

the role of natural gas in Asia.

In GES, a mathematical approach to search for the solution to a global climate change raised

by the Intergovernmental Panel on Climate Change was carried out. The research showed that natural

gas would be abundantly available throughout the century to meet increasing demand, and that using

natural gas was a robust option even when global climate change was taken into account.

However, the results shown in GES are globally optimal results, and an energy system that

realizes this sustainability can be discussed only when the specific characteristics of the individual

regions are reflected. In order to achieve this purpose, we have developed a new mathematical model

that enables analysis of energy systems, especially for natural gas, such as production, transmission

and conversion, in Asia, where large growth in energy demand is expected.

ES-2 Model structure

The newly developed energy infrastructure model is a mathematical model whose objective is

to minimize the total energy system cost for the world, with a detailed description covering Asia

including Oceania from 2000 to 2050. The objective function for the model is the total discounted

energy system cost for energy production, transportation, and consumption during the whole target

period for all over the world.

The primary energies considered in the model are fossil fuels, such as coal, oil, and natural gas,

various renewable energies and nuclear. Also, in order to analyze the sustainable world, an upper limit

for the greenhouse gas CO2 emission, which is derived from GES and enables the world CO2

concentration to be kept lower than 550 ppmV, is applied to the model. Energy savings arising from

cost increase of energy are also taken into account.

With these settings, the model can analyze energy systems to find those which will minimize

the energy system cost by satisfying the energy demand on one the hand and by satisfying CO2

emission limits on the other hand. In this report, the analyses are focused on the development of

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natural gas infrastructure, transmission, trading, and usage of natural gas, and on CO2 reduction

options.

ES-3 Model data settings

In order to ascertain the role and potential of natural gas in Asia, a dataset of IPCC B2 scenario

energy demand with some additional modification based on our original knowledge is chosen for the

Base Case scenario, which assumes mid-size economic growth. Focusing on a technology

improvement for a demand side technology, another assumption is made that fuel cell utilization will

gradually grow in the whole world and also in Asia.

ES-4 Base case results

Natural gas transportation

In Asia, natural gas transportation is quite so limited except for LNG transmission to Japan,

Korea, and Chinese Taipei, whereas pipelines are used just for connecting between production areas

and neighboring consumption areas.

In spite of this situation, according to the model based analysis, looking around 2020 to 2030,

intensive international natural gas transmission pipelines from Russia and the Middle East are

constructed to northern Northeast Asia and South Asia where energy resources are scarce relative to

energy demand growth. In contrast, in areas where enough resources exist, short but high capacity

transmission gas pipelines are constructed just between resources and demand areas. LNG trade

becomes aggressive in coastal areas of China and eastern India.

In the year 2050, the extension of individual routes, and also the expansion of individual

networks to the neighboring networks are observed. In particular, transmissions from Central Asia to

India and from West Siberia to China, connections between north and south within China, and

transmission from Papua New Guinea to Australia are also observed.

LNG transportation levels to northeast Asia are now approximately 70mil t-LNG, but will

continue to grow, especially in China, until 2030 followed by the expansion in India until 2050, until

finally LNG trade achieves 5 times of the current transmission level. The main destinations for

transmission are Northeast Asia and South Asia.

The amount transmitted by pipeline in Asia is currently almost zero, but this increases very

rapidly. If pipeline magnitude (throughput times distance) is expressed with normalized throughput, i.e.

20 bcm/year, around 50,000 km of pipeline will be constructed during the first 20 years, which is

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equivalent to the sum of European major international trunk lines in the same terms, and by 2050, the

network will extend to 230,000km which is equivalent to the current US domestic pipeline network

expressed in the same units.

Natural gas suppliers to Northeast Asia and South Asia where the energy demand increases

are as follows. For Northeast Asia, current suppliers like Southeast Asia and Oceania will continue to

supply almost the same amount, whereas pipeline supply from Russia and LNG from the Middle East

will exceed the amounts from these existing suppliers and will keep growing until the end of the target

period. The natural gas supply for South Asia mainly comes from Middle East, with 78% of flow

transported by pipe and 22% transported as LNG.

Role of natural gas

One result from the model is the demonstration that as the natural gas use increases, around

2040 to 2050 natural gas supply will become compatible with current major fuels, oil and coal. However

the regional production of natural gas will hit a plateau at around 2020 to 2030 and, at 2050, natural gas

imports to the Asia-Oceania region will account for three quarters of natural gas consumption in the

region. Also, three quarters of the natural gas imported will come through pipelines. In the power

generation sector, additional power generation using natural gas is a valid option for meeting increasing

electricity demand.

For reducing CO2 emissions, an energy shift to natural gas and energy saving will enable the

attainment of emission targets that will keep the world CO2 concentration lower than 550 ppmV during

the 21st century. Also, it is shown that adding natural gas based power generation is viable in terms of

cost even if the CO2 emission reduction does not become the world target.

ES-5 Conclusions

From the model based analysis, we could demonstrate that, even in Asia, natural gas can be a

sustainable solution, satisfying energy demand and also satisfying global environmental issues by

constructing natural gas infrastructure such as pipelines and LNG facilities.

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Résumé

ES-1 Introduction

Ce rapport vise à décrire le futur de l’infrastructure de l’énergie et notamment celui de

l’infrastructure du gaz naturel en Asie, dans le cadre du Projet spécial sur les “Global Energy Scenarios

(GES, Scénarios de l’énergie mondiale)”, au sein du programme triennal 2000-2003 de l’Union

Internationale de l’Industrie du Gaz et puis, à finalement analyser le rôle du gaz naturel en Asie.

Pour trouver une solution aux problèmes découlant du changement climatique mondial

soulevés par la Commission intergouvernementale sur le changement climatique, une approche

mathématique a été adoptée dans le cadre des GES. La recherche montre que, tout au long de notre

siècle, le gaz naturel devrait être disponible en abondance pour répondre à la demande croissante et

que l’utilisation du gaz naturel est une option sûre même lorsque l’on prend en compte le changement

climatique global.

Cependant, les résultats apparus dans les GES sont des résultats globalement optimaux et un

système d’énergie pouvant atteindre cette durabilité ne peut être examiné que lorsque les

caractéristiques spécifiques des régions individuelles sont représentées. Dans l’intention d’y parvenir,

nous avons développé un nouveau modèle mathématique qui permet d’analyser, notamment pour le

gaz naturel, les systèmes d’énergie tels que la production, le transport et la conversion en Asie, où l’on

s’attend à un grand essor de la demande en énergie.

ES-2 Structure du modèle

Le modèle d’infrastructure de l’énergie qui vient d’être développé est un modèle mathématique

dont l’objectif consiste à réduire le coût du système d’énergie total pour le monde entier, avec une

description détaillée couvrant l’Asie, y compris l’Océanie, entre les années 2000 et 2050. La fonction

objective de ce modèle est le coût total du système d’énergie avec réduction, pour la production

d’énergie, le transport et la consommation pendant toute la période visée et ce, dans le monde entier.

Les énergies primaires prises en considération dans ce modèle sont les combustibles fossiles

tels que le charbon, le pétrole et le gaz naturel, les diverses énergies renouvelables et le nucléaire. De

plus, afin d’analyser le monde des ressources durables, une limite supérieure pour les émissions de

CO2 des gaz de serre, dérivée des GES et permettant de garder la concentration mondiale du CO2

inférieure à 550 ppmV, a été appliquée à ce modèle. Les économies d’énergie survenant de

l’augmentation du coût de l’énergie sont également prises en considération.

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Avec ces paramètres, le modèle peut analyser les systèmes d’énergie pour trouver ceux qui

réduiront le coût du système d’énergie en satisfaisant la demande d’énergie, d’une part ainsi que la

limite des émissions de CO2, d’autre part. Dans ce rapport, les analyses sont concentrées sur le

développement de l’infrastructure du gaz naturel, la transmission, le commerce et l’utilisation du gaz

naturel et sur les options de réduction de CO2.

ES-3 Paramètres de données du modèle

Dans le but d’établir le rôle et le potentiel du gaz naturel en Asie, nous avons utilisé un

ensemble de données concernant la demande d’énergie du scénario IPCC B2 auquel nous avons

intégré quelques modifications supplémentaires en fonction de nos connaissances initiales pour la

demande en énergie du scénario de cas de base, qui suppose une croissance économique moyenne.

En se concentrant sur une amélioration de la technologie pour une technologie côté demande, nous

pouvons aussi supposer que l’utilisation des piles à combustible va s’accroître progressivement dans le

monde entier et également en Asie.

ES-4 Résultats du cas de base

Transport du gaz naturel

En Asie, le transport du gaz naturel est vraiment assez limité sauf pour l’acheminement du

GNL vers le Japon, la Corée et le Taipei chinois où les pipelines sont simplement utilisés pour relier les

zones de production et les zones de consommation avoisinantes.

En dépit de cette situation, selon une analyse basée sur le modèle, aux environs des années

2020 à 2030, un réseau international de pipelines acheminant intensivement du gaz naturel de Russie

et du Moyen-orient sera construit dans le nord de l’Asie du Nord-Est et en Asie du Sud où les

ressources en énergie se font rares du fait de la croissance de la demande en énergie. Par contre,

dans les zones où des ressources suffisantes existent, des gazoducs courts mais de grande capacité

seront construits seulement entre les zones de ressources et de demandes. Le commerce du GNL

deviendra agressif dans les régions côtières de la Chine et de l’est de l’Inde.

En 2050, on verra l’extension des circuits individuels et aussi l’expansion des réseaux

individuels aux réseaux avoisinants. On verra aussi, en particulier, des acheminements en provenance

de l’Asie centrale vers l’Inde et de la Sibérie de l’ouest vers la Chine, des connexions entre le nord et le

sud à l’intérieur de la Chine et des acheminements de la Papouasie-Nouvelle-Guinée vers l’Australie.

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Les niveaux d’acheminement du GNL vers l’Asie du Nord-Est s’élèvent maintenant à

pratiquement 70 millions de tonnes de GNL, mais continueront à croître, notamment en Chine, jusqu'en

2030 suivis d’une expansion en Inde jusqu'en 2050, jusqu’à ce que finalement, le commerce du GNL

atteigne 5 fois le niveau du transport actuel. Les principales destinations seront l’Asie du Nord-Est et

l’Asie du Sud.

En Asie, la quantité acheminée actuellement par pipeline est pratiquement nulle, mais elle

augmente très rapidement. Si l’importance du gazoduc (débit multiplié par la distance) est exprimé

avec un débit normalisé, c’est-à-dire 20 milliards de mètres cubes/an, quelque 50 000 km de pipeline

environ seront construits pendant les 20 premières années, ce qui est équivalent à la somme des

principaux pipelines internationaux européens dans les mêmes termes et, d’ici 2050, le réseau

s’étendra à 230 000 km, ce qui est l’équivalent du réseau actuel de pipelines national des Etats-Unis,

exprimé dans les mêmes unités.

Les fournisseurs de gaz naturel de l’Asie du Nord-Est et de l’Asie du Sud où la demande

d’énergie augmente, se présentent comme suit : Pour l’Asie du Nord-Est, les fournisseurs actuels

comme l’Asie du Sud-Est et l’Océanie continueront à fournir pratiquement la même quantité, alors que

la fourniture des pipelines de Russie et du GNL du Moyen-Orient dépassera les quantités des

fournisseurs existants et continueront à s’accroître jusqu’à la fin de la période visée. La fourniture de

gaz naturel pour l’Asie du Sud provient principalement du Moyen-Orient, avec 78 % du débit transporté

par pipeline et 22% transporté en tant que GNL.

Rôle du gaz naturel

Un des résultats découlant du modèle est la démonstration que, tandis que l’utilisation du gaz

naturel augmente autour de 2040 à 2050 la fourniture du gaz naturel deviendra compatible avec les

principaux combustibles actuels, le pétrole et le charbon. Cependant, la production régionale du gaz

naturel atteindra un plateau entre 2020 et 2030 et, en 2050, les importations de gaz naturel de la région

Asie-Océanie représenteront les trois-quarts de la consommation de gaz naturel dans la région. De

plus, les trois-quarts du gaz naturel importé sont acheminés par des pipelines. Dans le secteur de

production d’énergie, une production d’énergie supplémentaire utilisant le gaz naturel est une option

valable pour répondre à la demande croissante en électricité.

Pour réduire les émissions de CO2, un changement d’énergie en faveur du gaz naturel et des

économies d’énergie autoriseront la réalisation de l’objectif d’émission qui permettra de conserver la

concentration mondiale de CO2 inférieure à 500 ppmV tout au long du 21ème siècle. En outre, il est

démontré que l’addition de la production d’énergie basée sur le gaz naturel est viable en termes de

coût même si la réduction d’émission de CO2 ne devient pas l’objectif mondial.

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ES-5 Conclusion

A partir des analyses basées sur le modèle, nous pouvons démontrer que, même en Asie, le

gaz naturel peut s’avérer une solution viable, satisfaisant la demande d’énergie et satisfaisant

également les questions liées à l’environnement global, en construisant une infrastructure pour le gaz

naturel telle que des pipelines et des installations pour le GNL.

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1. INTRODUCTION

1.1 Global climate change

Global climate change, such as global warming, is thought to be caused by the emission of

greenhouse gases emitted by human activity. Six different greenhouse gases were defined and

quantified emission reductions for each country were set in the Kyoto Protocol, adopted during “The

Third Session of the Conference of the Parties (COP3)” to the United Nations Framework Convention

on Climate Change (UNFCCC) held in 1997.

Of all of these six greenhouse gases, carbon dioxide, CO2, contributes the most to the global

warming problem because of the amount of emissions and its long lasting nature. And, furthermore,

more than 70% of CO2 emissions from human economic activity result from the combustion of fossil

fuel in energy systems. Consequently, in order to tackle global warming, a large reduction in CO2

emissions from energy systems is crucial.

In 2000, global CO2 emissions were approximately 6.4 Gt-C/year (6.4 gigatons of carbon), of

which 54% was emitted from developed countries whose population accounts for only 19% of the world

population. Considering the speed of development of developing countries and the growth of their

energy consumption, the formation of a policy is necessary that will enable both economic growth and

action to counter global warming. In particular, because CO2 emissions can cross borders and affect

the entire world, concerted action between developed and developing countries should be taken that

goes beyond borders.

1.2 Energy in Asia

Even though Asia and Oceania account for 55% of the world population, commercial energy

consumption in those regions was approximately 28% of the total global consumption in year 2000.

However, over the past three decades, commercial energy consumption in Asia and Oceania has

grown by 4.1% per annum, 2.1 percentage points higher than the global growth rate. In particular,

Korea, China, India and Southeast Asia haven shown significant growth in energy demand.

Energy in Asia relies on coal, which exists abundantly in the region, and oil, which is also

extractable within the region and is easily transported. However, in Asia, where the demand for energy

is expected to grow, both from global and local environmental perspectives, coal should be replaced

with a newer form of energy system because its CO2 emission coefficient is higher than that of other

fossil fuels. A crucial regional issue in order to achieve this is to outline a plan for developing Asia's

energy infrastructure that will both meet growing energy demand and solve the global environmental

issue while maintaining regional economic growth.

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Figure 1: Trend in fuel-wise primary energy consumption in Asia-Pacific.

Source: Appendix- A

1.3 Purpose of the project

The “Global Energy Scenario” (GES), one of two special programmes for IGU's Triennium

Work Programme of 2000-2003, has analyzed solutions using natural gas and its role as pertains to the

global warming issue that was raised by the Intergovernmental Panel on Climate Change (IPCC),

which takes a scientific approach to climate change issues. As a result of this research, it was

determined that natural gas would be abundantly available throughout the century to meet increasing

demand, and that using natural gas was a robust option even when global climate change was taken

into account.

However, the results shown in the GES are optimal globally, but that does not mean the

solution is optimal locally or nationally. This is mainly because of the great differences in factors

affecting the future of energy such as geological factors, natural conditions, the amount and

accessibility of energy resources, production costs, transportation methods and costs. Energy policy is

defined by national or regional collaboration based on these factors.

With all of these findings, we decided to develop a precisely described mathematical simulation

model in order to fully analyze a solution to global warming issues on a national level. The aim of this

model is to describe the precise energy system, from production to consumption, as well as detailed

coverage on the regional and national levels, given the restriction of a certain level of CO2

concentration during the 21st century. The ultimate purpose of this model is to describe the role of

natural gas.

The target regions that were chosen for analysis were Asia and Oceania, where regional

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energy demand will continue to grow but almost no energy transmission systems exist. The

development of energy infrastructure to support sustainable development in Asia, particularly natural

gas production, transmission, and consumption for the coming 50 years, is examined.

In Chapter 2, an outline of the newly developed Asia Energy Infrastructure Model, which is

based on detailed global energy transmission, is described. In Chapter 3, the major assumed data set

used for the analysis is described. Chapter 4 is shows the results from the model analysis, and Chapter

5 provides the conclusion of the analysis.

Readers may find two appendices at the latter part of this report. Appendix A, “Reviews of

natural gas market in Asia”, is a contributed paper from The Energy and Resources Institute (TERI),

India, and the Asian Energy Institute (AEI), a network of energy institutes from Asia and relating

countries. This report describes on the current natural gas status in Asia from the standpoints on

resources, demands and sub-regions.

Appendix-B, “Storylines on Asia’s Natural Gas Perspectives”, is a co-work report with the

Institute of Energy Economics, Japan (IEEJ), and the National Organizing Committee of the World Gas

Conference 2003. In this report, important and uncertain driving forces on the future of natural gas in

Asia are organized and compiled into two storylines.

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2. MODEL STRUCTURE

2.1 Model outline

The model is a new kind of global energy transportation model capable of more precisely

representing data on Asia over the 50-year period from 2000 to 2050 every 10 years.

The objective function of this model is the total sum of the discounted cost of the energy

system, such as primary energy production, energy transportation, energy conversion facilities, CO2

recovery and transportation, and demand decrease, that satisfies the given energy demands over the

target period. By obtaining the set of variables that minimize this objective function, we are trying to

trace the development of the world's energy system, particularly in Asia, under conditions such as

given resources and global CO2 emission limits.

This model divides the world into 115 regions based on their geopolitical features and natural

environments, and one major city is chosen as the point of reference in each region. Out of all nodes,

75 nodes are assigned in Asia so that precise analysis is available in that region. At each node,

producible primary energy resources are assigned, such as the fossil fuels coal, oil, and natural gas,

renewables like biomass, solar, hydro, wind and geothermal power, and nuclear power. A set of

production costs for each energy source is also defined by node.

Produced energy resources at each node can be consumed as they are or can be converted

into other forms of energy. Also, the produced energy at some nodes can be transported by sea or land

to other nodes to satisfy their demands. All these kinds of costs, like transmission and conversion, are

defined by node and route.

Based on these detailed definitions, the objective function will be calculated and the optimal

solution that minimizes this function is derived as a global cost-minimum infrastructure.

Another characteristic for this model is that it can take into account CO2 emission control such

as CO2 recovery, CO2 transmission, CO2 storage, and demand decrease occurring due to

demand-price elasticity.

The model can keep the environmental concentration of CO2 within a certain range by applying

limitations to world CO2 emissions from time to time. The model can control CO2 emissions by changing

energy systems and also by recovering CO2 in order to meet the CO2 limitation.

Demand decrease or energy saving is taken into account as an option for CO2 decrease as

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well as CO2 recovery and storage. This is achieved through the linearized formulation of demand

decrease occurring due to the price increase of energy: demand-cost elasticity.

Figure 2 indicates major data, constraints, the objective function, and major outputs induced

from the model calculation result.

Hereinafter, model data settings, such as assumed geological settings, defined energy

systems, and energy transmission routes between divided regions, are described. The mechanism for

the demand decrease due to price-demand elasticity is also described.

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Energy extraction•Primary Energy ResourcesAmount & production cost by grade(Coal, Oil, Natural Gas, Renewables, Nuclear)

Conversion•Power plant cost•Chemical plant cost•CO2 recovery cost•Efficiency

Transportation•Energy, CO2(Pipeline, Tanker,Train, Collier)•Construction cost•Distance•Efficiency

Energy consumption•Energy demand(Solid, Liquid, Gaseous, Elec.)•CO2 storage(Cost & Capacity)

Initial values•Primary energy use•Final energy consumption•Plant capacity•Transportation capacity

Others•Discount rate•Long term demand-price elasticity•World CO2 emission limit

Major data setting

Constraints•Demand & supply balanceby node, sector and time•Trade balanceby node, sector, and time•CO2 world emission limitationby time•CO2 storage balance•Growth limit for energyby source•Power generation limitfor Nuc. and Renewablesby time and node•Regional dependency

Objective function= Sum of total cost by time and nodes•Energy production•Energy conversion•Transportation•Construction(plant, transportation)•Demand decrease cost

Model calculation

By time, node, link & sector

•Primary energy production•Secondary energy conversion•Final energy consumption=> Energy trade, energy balance

•Energy transportation=> Energy infrastructure

•CO2 storage, transportation=> CO2 trade, CO2 balance•Plant capacityPower, chemical, CO2 recovery

Model outputs

•Model based analysis by IGU Strategic Programme “Global Energy Scenarios” and model analysis by “DNE21”

CO2 emission scenario







Major data setting







Major data setting



Model calculation



Model calculation





Model outputs





Model outputs





Figure 2: Model major data settings, constraints, objective function and outputs

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Division of regions

In order to represent geographical characteristics of the world, particularly for Asia, this model

divides the world into 115 detailed regions. At first, the world is divided into some rough regions so that

each regional coverage on economics and population is equal, and then for each country in Asia more

than one region is assigned. Some larger countries with a large geographical or economic size are

divided into multiple regions. The total number of regions is 115, 75 of which are in Asia.

One major city was chosen as the representative of each region, which is called a “node”, and

various data, such as energy resources and energy demand within the region, are set by taking into

consideration its geopolitical features, such as its reserves of natural resources, natural environments,

population size, level of economic activity, and energy consumption pattern.

The map in Figure 3 indicates the assigned nodes for this model. Here, nodes represented with

boxes indicate the production nodes with no energy demand, and nodes represented with circles

indicate the demand nodes where all the regional energy demand is concentrated upon the node.

Figure 3: Defined 115 nodes for energy model.

Energy systems

In the Asian energy infrastructure model, each node has its own energy system that, among

other things, produces and converts energy, generates electricity, consumes energy and recovers CO2.

Table 1 shows some of the main internal energy production, conversion and consumption

within the node. Among the primary energy supply, not only fossil fuels such as coal, oil and natural gas,

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but also renewable energies, such as biomass, hydro & geothermal, solar, and wind power, and nuclear

power are considered. Demand for four different types of energy consumpition -- solid, liquid, gaseous,

and electricity -- are considered.

Produced primary energy can satisfy the final energy demand directly, but it can also satisfy

other forms of energy demand by using chemical conversions or the electrolysis process.

Table 1: Energy systems at each node.

As for the power generation processes, coal can be used not only for the fuel source of

conventional thermal power stations but also for the fuel source of Integrated Gasification Combined

Cycle (IGCC) thermal power stations that can recover CO2, and oil is used for thermal power, and

natural gas (including methane) and hydrogen include not only thermal but also fuel cell based power

stations. Renewable energies based power and nuclear power are also taken into account.

CO2 recovery from chemical plant and flue gas from fossil fuel power stations is considered

with chemical absorption and physical absorption processes. Recovered CO2 can be used for

Enhanced Oil Recovery (EOR), or can be stored into geologically stable areas such as deep aquifers,

depleted gas wells, and deep ocean floors located 1000 km away from the shore.

1. Primary energy production

• Fossil fuel (Coal, Oil, Natural Gas)

• Biomass

• Nuclear power

• Hydro geothermal power

• Solar power

• Wind power

2. Energy consumption

• Solid demand

• Liquid demand

• Gaseous demand

• Electric demand

3. Energy conversion

• Fossil fuel to hydrogen, methane, GTL

(methanol, kerosene, light oil, DME)

• Water electrolysis

4. Power generation (10 types)

• Coal fired thermal power

• Oil fired thermal power

• Natural gas (methane) fueled power

• Integrated Gasification Combined Cycle

power (IGCC)

• Nuclear power

• Hydro geothermal power

• Solar power

• Wind power

• Biomass

• Hydrogen fueled power

5. CO2 recovery (2 types), storage (4 types)

• Chemical absorption

• Physical absorption

• Injection for enhanced oil recovery

• Geo-storage (depleted gas well, aquifer)

• Ocean storage

16

All primary and secondary energies except renewables and CO2 produced at each node can

be transported to other nodes. Precise description on transmission will be shown later on.

An outline of the described energy flow is shown in Figure 4.

CO2SequestrationCO2Sequestration

Oil

Natural Gas

Biomass

Hydro,Geo,Nuc, PV, Wind Power Generation

Gaseous Fuel

Liquid Fuel

Solid Fuel

Electricity

Gasification

Reformation

CO2 Sequestration

Methane

GTL

Hydrogen

Coal

To Other Nodes

From Other Nodes

Figure 4: Energy conversion systems at each node.

Energy transmissions

In this model, in order to formulate the trade of energy and CO2 between regions, transmission

of these is assumed to be enabled only between nodes, and, as its actual route, land routes for

pipelines (including underwater pipelines) and trains and ocean transport routes for ships are defined.

Almost all linkages connecting neighboring nodes are assumed to be for land transportation based on

the actual geographical characteristics, for example, passing over mountain ranges or under the sea.

Sea transportation is available not only between coastal nodes but also between nodes accessible to

the ocean via approximately 1000 km of land transportation. Finally, we have chosen 239 routes for

land transportation and 3570 routes for ocean transportation, and, along each transmission route,

various kinds of energies will be transported in either direction.

Figure 5 shows the model setting for transportation routes. Figure 6 is an enlarged map of Asia

17

in which intensive analysis will be done hereafter.

Figure 5: Possible marine and land transportation links between nodes.

Figure 6: Asia and neighboring regions.

18

Energy conservation logic

In this model, a set of energy production and transmission is derived to satisfy four forms of

demand and a set of CO2 recovery, transmission, and storage is derived to satisfy the CO2 restriction at

each node. However, the introduction of CO2 limitation policy will also cause energy price hikes and

may induce energy demand decrease and change the constitution of energy demand itself. In order to

implement this mechanism, which is energy demand- price elasticity, a mathematical formulation is

considered as follows.

In the end use demand sector where no CO2 limitation exists, the energy reference price is 0P

and the reference energy demand is 0D . Next, if the long term price elasticity of energy demand is

α− ( 0>α ), then energy demand ( )PD is expressed as follows when energy price is P .

α−= )()(0

0 P

PDPD ( 0>α )

The energy price P is found from this formula, and the next formula is obtained by

introducing energy savings S .

α/1

0

00 )()( −−

=D

SDPSP ( )0>α

The cost function of energy conservation can thus be expressed as follows:

−−−

==−

∫ 1)1(1

)()(1

0000

αα

αα

D

SPDdSSPSC

S ( )1≠α

The reference energy demand 0D already includes energy conservation induced from

general energy price rises and technology improvements, among others.

By referring to the history of energy demand-price elasticity for developed countries,

4.0−=α

was chosen. The initial value 0P for the energy price at 2000, was adjusted depending on the

node based on the actual price.

This function is non-linear, and is not directly applicable to the model because it is a linear

optimization model. A stepped approximation of the energy conservation function is therefore obtained

and then the function linearized as shown in Figure 7.

19

Demand (TOE)

Pric

e ($

/TO

E)

0D0D

α/1

0

00 )()( −−

=D

SDPSP

α/1

0

00 )()( −−

=D

SDPSP

Step function

α/1

0

00 )()( −−

=D

SDPSP

α/1

0

00 )()( −−

=D

SDPSP

x(sp,2)x

D0

x(sp,1)x

D0

P0=PS

P’(sp)

Figure 7: Energy conservation function and stepped approximation.

2.2 Determination of basic data

The major model defined data for this model, such as primary energy resources, production

costs, construction costs, operation costs and efficiency data for transmission facilities and various

plants, are described below.

Fossil fuel resources

Various assessments have been carried out for the amount of fossil fuel resources and

reserves. However, most of the data represents “proven recoverable reserves” which have market

value in the next few decades. Table 2 is a comparison between various researches for natural gas

resources (and reserves), and it is commonly recognized that proven reserves for natural gas are

approximately 150 tcm (trillion cubic meter), and equivalent to 60 to 70 years for the

resource-over-production ratio. [1, 2, 3, 4] Additional resources can also be expected, and, as shown in

Rogner, the expected total amount of available natural gas is 469 tcm from conventional resources.

In order to execute the 50-year long-term analysis, in this model, we have assumed that

additional resources wi ll become available from undiscovered reserves due to exploration and

technology improvements.

In the model, the resources coal, oil and natural gas are assigned to each node, based on data

from USGS and Rogner. six to seven grades of category are assumed for each energy resource

because the production cost differs by production area, depth and so on. In this model, only

conventional fossil fuel resources are considered and unconventional resources, such as tar sand and

coal bed methane, are not taken into account. The reason for this is because the target period of this

20

model is 50 years long, and there would be enough resources to support this period. Even if

unconventional resource production does not start until the end of the period, the amounts would

substitute for higher categories of energy grades.

USGS WPA2000 IGU 2003 WOC9 BP Stat. 2002 H-H Rogner

1995~2025

Remaining Reserves

…135 tcm

Reserve growth (F50%)

…93.3 tcm

Undiscovered

…122 tcm

Proven

…173 tcm

Additional

…94.9 tcm

Potential

…238 tcm

Proven

…155 tcm

Conventional

…469 tcm

Unconventional

…413 tcm

+Additional

…403~1990 tcm

Table 2: Assessment of natural gas reserves.

The total world fossil fuel resources of 10 regions are shown in Figure 8. The total assumed

world resources for coal, oil, and natural gas are 3749 GTOE (giga ton of oil equibalent), 407 GTOE

and 426 GTOE respectively. A precise description of category and data settings can be found at the

end of this chapter.

Production costs of fossil fuels

Production costs by category and by region are defined based on the paper by Rogner. Even

though the basic costs are same within the region, at each node where current production is aggressive,

the cost is set to cheaper, and the cost at nodes in polar and remote areas is multiplied by 1.5 to 2.

The production costs varies from place to place, and category to category. Figure 9 shows the

cumulative production cost of world fossil fuels based on the model data setting.

21

a) Coal (Total 3749 GTOE)

0 200 400 600 800 1000 1200 1400 1600 1800

N.America

W.Europe

Japan

Oceania

China

Other Asia

ME & Sub Sahara

S. Africa

Latin America

FSU & E.Europe

Category 1

Category 2

Category 3

Category 4

Category 5

Category 6

b) Oil (Total 407 GTOE)

0 20 40 60 80 100 120 140 160 180 200

N.America

W.Europe

Japan

Oceania

China

Other Asia

ME & Sub Sahara

S. Africa

Latin America

FSU & E.Europe

Category 1 Category 2 Category 3 Category 4

Category 5 Category 6 Category 7

c) Natural gas (Total 426 GTOE)

0 20 40 60 80 100 120 140 160 180 200

N.America

W.Europe

Japan

Oceania

China

Other Asia

ME & Sub Sahara

S. Africa

Latin America

FSU & E.Europe

Category 1

Category 2

Category 3

Category 4

Category 5

Category 6

Category 7

Figure 8: Resource amounts for fossil fuels by region.

22

0

20

40

60

80

100

120

140

160

180

200

0 100 200 300 400 500

Cumulative Prod. (Gtoe)

Uni

t P

rod.

Cos

t($/

toe)

Coal

Natural Gas

Oil

Figure 9: Cumulative production cost for fossil fuels.

Renewable resources

As renewable energy, hydraulic, geothermal, solar, and wind are assumed to be sources for

power, and biomass is considered for various uses such as fuel wood and sources for chemical

conversions. The potential for hydraulic power is estimated from the WEC Survey [5].

Meteorological data for world solar resources is obtained from the world satellite solar data

from the NASA SeaWiFS irradiation data. [6]. Irradiation data plotted on the world map is shown in

Figure 10. Wind data is obtained from the National Climate Data Center of the NOAA [7], then

averaged and plotted on the map as shown on Figure 11. In order to allocate the potentials of these

renewable energies to each node, both data are applied together with world land use data from the

AARS Global 4-minute Land Cover Data Set [8] (Figure 12) by Chiba University.

23

Figure 10: Annual averages of solar irradiation based on satellite data.

Source: Assembled from NASA SeaWiFS

Figure 11: Average wind speed distributions.

Source: Assembled from NOAA National Climate Data Center

24

Figure 12: World land use.

Source: Center for Environmental Remote Sensing, Chiba University

Energy transportation costs

Various energy transportation methods are considered such as coal train and coal collier, and

similarly pipelines and tankers for oil, natural gas and other liquid or gaseous energy. Gaseous energy

such as natural gas and hydrogen is transported in a liquefied state, and, in order to change the state,

liquefaction and re-gasification facilities are required at shipping and receiving nodes, respectively, and

capacity thereof must match the amount of trade.

Electricity transmission is available only with land routes by DC-high-voltage-transmission in

this model. Although it is not a form of energy, CO2 can be transported between nodes by pipelines and

tankers. No transportation method is considered for biomass.

Rather than being expanded linearly, energy transportation infrastructure is normally

developed by initially providing somewhat more capacity than required in anticipation of future growth

in transportation due to demand growth. In order to simplify the calculations for the model, however, the

capacity of each type of energy infrastructure was treated as a linearly expandable continuous function,

and the minimum necessary capacity always used.

In this model, unit transportation cost is defined as the annual cost of transporting unit energy

over unit distance. The unit cost is subdivided into fixed costs (construction costs) and variable costs

(operation and maintenance fees), and, furthermore, these costs are defined as combinations of

distance dependent and distance independent terms. In order to derive these unit costs, various data

for construction costs are examined and calculated with annual discounted rates and other parameters.

25

By reflecting the actual energy systems, transmission losses, internal use, and operation

electricity are considered for tankers, pipelines, electricity transmission, liquefaction plants, and

gasification plants inclusively.

Table 3 indicates annual transportation costs for carrying a unit of energy a distance of L×1,000

km. Also, Figure 13 shows a graph of the cost-distance relationship for various types of energy

transportation. Here, in this graph, ocean transportation for gaseous energy and CO2 includes the cost

for liquefaction and gasification plants. (CO2 transportation does not include gasification cost.) Table 4

indicates liquefaction and gasification costs by gas.

The base data sets are obtained and defined through multiple data sources. Concerning about

natural gas, natural gas pipeline costs are assumed from European study, and LNG costs are obtained

from the analysis on Asian LNG projects. LNG liquefaction and re-gasification costs include LNG

storage facilities to some amount.

As seen on Figure 13, transportation costs vary greatly depending on the form of energy. In

general, gaseous energy transportation by sea, like LNG and hydrogen transportation, costs more than

other fuels like coal and oil because of the need for the liquefaction and re-gasification process. In the

model data setting, costs for mountainous or underwater routes are set higher depending on the

geographical characteristics.

Also, as described above, costs are expresses with a set of representative data, regional

differences must be taken into account, especially for pipeline. Thus, for example, pipeline installation

costs in Japan are set to be four times higher than that of base data because of the crowded land use

of Japan and differences of regulations on pipeline installation, such as the lack of the concept of “Right

of Way”.

Cost ($/TOE per· year) Coal by Train 30.0 × L Oil PL 6.0 × L Natural Gas PL 20.5 × L Coal by Collier 1.01 × L+10.15 Oil Tanker 0.6 × L+ 6.17 LNG 4.95 × L+100.7 HVDC 91.6 × L Hydrogen PL 38.0 × L Hydrogen Tanker 10.27× L+216.86

Table 3: Assumed energy transportation unit Cost.

($/TOE per year, L: transportation distance [unit: 1000 km])

26

0

100

200

300

400

0 2,000 4,000 6,000 8,000 10,000 12,000

km

$/TO

E

Coal Train

Oil PL

Natural Gas PL

Coal Collier

Oil Tanker

LNG

High VoltageDC Trans.

Hydrogen Tanker

Hydrogen PL

Figure 13: Energy transportation cost by distance

Fixed cost: $/(TOE/year)

Operation cost: $/(TOE/year)

Internal use (MWh/TOE)

Natural gas liquefaction 48.9 22.2 0.97 Natural gas gasification 14.8 6.7 - Hydrogen liquefaction 120.1 - 3.329 Hydrogen gasification 89.5 - - CO2 liquefaction 46.44 0.733

Table 4: Liquefaction and re-gasification costs for gases.

Power Plants

The power generating sector has an extremely important role to play in combating global

warming because it has various options for reducing CO2 emissions. Technologies for supplying

non-fossil energies, such as nuclear and solar power, attract interest because of their potential for

energy conversion, and, in almost all cases, they are related to electric power generation. Technologies

for the separation and recovery of CO2 emissions are also being considered primarily as a means

removing of CO2 from the flue gas of thermal power stations. Unlike other forms of energy demand

(solid, liquid, and gaseous), electricity demand can be met from most energy sources, increasing the

flexibility of the power generating sector in combating global warming.

Coal, oil, natural gas, hydrogen, methanol, biomass and IGCC thermal power plants were

considered. IGCC are plants that generate power from coal gas, and, in this model, IGCC plants are

assumed to be equipped with CO2 recovery systems, as mentioned later. Also, because of this

equipment, its plant parameters include an efficiency decrease and cost increase.

27

0

0.1

0.2

0.3

0.4

0.5

0.6

2000 2010 2020 2030 2040 2050

Effi

cien

cyCoal Fired

Oil Fired

Natural gas fueled

Hydrogen fueled

IGCC

Methanol Fired

Figure 14: Efficiency of different power generation types.

The base power generating efficiency was assumed to increase toward 2050 as shown in

Figure 14. Regional disparities in power generating efficiency were assumed, and the base power

generating efficiency mentioned above was multiplied by the coefficient for each region to determine

the power generating efficiency of each region and node. The disparity by region was also set to shrink

toward 2050.

Here, we have set relatively high base power generating efficiencies (60% at 2050) for

hydrogen and natural gas. This is mainly because the Advanced Combined Cycle system has already

achieved generation efficiencies of 50%. Also, as this is still in the experimental or prototype stage,

Solid Oxide Fuel Cells, which will be used for large scale power plants in the future, also achieves 50%

and, when operated under pressurized fuel gases with high operation temperature around 750-1000

degree Celsius, the flue gas from the fuel cell can operate the gas turbine to extract additional power.

This SOFC/GT Hybrid power generation system will be able to achieve 60-70% efficiency if fueled by

natural gas as shown in Box 1. (Efficiencies shown here are all LHV bases.)

Construction costs for each power plant are listed in Table 5 with their efficiency range. Annual

costs for each plant are calculated from the annual discounted rate, 17%, and the upper limit for plant

capacity utilization is set to 85%. Power plants are assumed to have a life of more than 50 years and

will exist during the target period, 2000-2050. Existing power plant capacity was adopted as the

minimum capacity.

28

Box 1 Fuel Cell/Gas turbine hybrids

Solid oxide fuel cells or SOFCs, for stationary use can have high efficiency of around 50-60%

in an atmospheric circumstance, but it can also achieve efficiency of 58% with a 250kW generator, 60%

with a 1MW, and 70% or more with a 2~3 MW fuel cell generator if operated at 3~7 atm pressurized

fuel air because of the increased efficiency of fuel cells and cascaded flue gas turbines. Its schematic

diagram is shown below.

(Efficiencies shown here are all LHV bases.)

Details of R&D progress and related topics on SOFC/GT hybrids can be found on the following

website:

http://www.siemenswestinghouse.com/en/fuelcells/index.cfm

SOFC/Gas Turbine Hybrid Cycle Diagram

Source: http://www.siemenswestinghouse.com/en/fuelcells/hybrids/performance/index.cfm

Construction cost ($/kW)

Efficiency (%)

Coal Fired 1,700 31.7~50.0 Oil Fired 850 34.3~52.0 Natural Gas Fired 750 36.7~60.0 Nuclear 2,000 33.0 (OECD) IGCC 2,100 29.1~41.5 Methanol Fired 1,450 40.0~55.9 Hydrogen Fueled 2,150 35.0~55.0

Table 5: Power plant construction costs and generation efficiency.

Energy conversion

The primary energies -- coal, oil, natural gas and biomass -- can be converted into hydrogen

(H2), carbon monoxide (CO), CO2, and methane (CH4) by passing through partial oxidation, reformation,

and shift reaction at chemical plants considered at each node. H2 can be used to satisfy gaseous

29

demand as a non-CO2 polluting gas.

Furthermore, synthesizing CO and H2, a sulfur free, clean liquid fuel can be obtained, for

example, as a substitute for kerosene and light oil, dimethyl ether (DME), or methanol. The CO2 from

these chemical reaction processes will be recoverable at a certain ratio depending on the process.

Figure 15 indicates the chemical reaction process. Table 6 and Table 7 show gas production,

consumption and plant construction costs for gasification and liquefaction chemical plants.

Coal/Oil/Natural Gas

Thermal Power Plant

GTL (Methanol, DME, etc)

Methanol

Methane

COCO2H2 H2O

CO2

CO2CO H2

H2

H2

H2CO

CO

CO2

+++

++

Gasification/Reformation

Recovery

Synthesis

Shift Reaction

Coal/Oil/Natural Gas

Thermal Power Plant

GTL (Methanol, DME, etc)

Methanol

Methane

COCO2H2 H2O

CO2

CO2CO H2

H2

H2

H2CO

CO

CO2

+++

++

Gasification/Reformation

Recovery

Synthesis

Shift Reaction

Figure 15: Energy conversion processes assumed in the model.

1 TOE H2 (TOE) CO (TOE) CO2 (t-C) Construction cost (104$/TOE/day)

Coal 0.297 0.400 0.369 21.2 Oil 0.377 0.455 0.029 17.8

Biomass 0.278 0.324 0.478 20.1 Natural gas reform 0.467 0.370 18.2

Table 6: Gasification plant costs.

1 TOE H2 (TOE) CO (TOE) CO2 (TOE)

Construction cost (104$/TOE/day)

Kerosene/Light fuel 0.794 0.464 14.8 CH4 from CO and H2 0.757 0.443 8.8 CH4 from CO2 and H2 1.136 0.787 9.7 DME Synthesis 0.726 0.425 12.3

Table 7: GTL plant costs.

CO 2 management

Energy conservation and energy conversion using renewable energies and fuels with low basic

units of CO2 emissions have been put forward as a way of reducing CO2 emissions caused by energy

consumption. This model, however, also considers another method, namely the recovery of the CO2

generated and its transmission to and store at a stable area.

30

[CO2 absorption]

CO2 recovery was assumed to occur at thermal power plants and chemical plants, with

recovery being by chemical absorption from the flue gas from thermal power plants, except for IGCC in

which case CO2 is recovered from the combination of physical absorption and shift reaction. Physical

absorption is considered only for CO2 recovery from chemical plants.

Table 8 indicates the construction costs and electricity consumption for each type of absorption

method.

Construction cost ($/t-C/day)

Internal use (MWh/t-C)

Chemical absorption 14,500 0.815 Physical absorption 56,500 0.066

Table 8: CO2 absorption plant costs.

[CO2 transportation]

CO2 transportation was assumed to be by pipeline on land, and by liquid gas tanker by sea.

The relationship between distance transported and cost is already shown in Figure 13.

[CO2 storage]

In the general, recovered CO2 can be applicable to EOR, or it can be injected into depleted gas

wells, deep underground aquifers, or the ocean. (See Box 2.) The use of EOR was assumed to

increase oil potential by 10%. Storing CO2 in depleted gas wells is a promising option because of their

geological properties for storing gas stably. In this mode, natural gas wells are defined as one field for

each node, and they are not applicable for analyzing the depletion of fields. Instead, the simple

assumption was made that the storable amount is in proportion to the produced gas. If examined

precisely by node, there would be enough capacity for the depleted gas wells to store CO2 for each

node.

CO2 storage into underground aquifers represents the sequestration method of dissolving CO2

into deep aquifers where humans will not usually access it so as to prevent the CO2 solution from

escaping into the atmosphere. CO2 spitted from natural gas production is already stored in aquifers in

Europe and the challenge has been made widely known. [9]

There are several options for CO2 in the ocean, such as dispersion and storage, but, in this

model, sequestration by liquefaction of CO2 into deep water ponds (deeper than 3000m) is chosen

because liquid CO2 is stable under deep ocean pressure.

Table 9 indicates CO2 storage costs and some additional conditions by storage method.

31

Storage cost ($/t-C) Additional Information EOR 87-125 Oil 1 TOE increase by 0.89t-C of CO2 Depleted gas well 46 Natural gas 1 TOE can store 0.589t-C of CO2 Aquifer 10-150 Internal use 0.269MWh/t-C Ocean 25 need 1000 km ocean transportation

Table 9: CO2 sequestration costs.

Box 2 CO2 Sequestration technologies

Separated CO2 should be stored into certain stable areas. Several methods for storing CO2 in

natural reservoirs underground or under the sea are proposed and under research. Current research

developments in CO2 storage technologies can be found on the website for IEA Greenhouse gas

control at

http://www.ieagreen.org.uk/removal.htm.

CO2 usage

• CO2 injection for Enhanced Oil Recovery

• CO2 for industrial use

CO 2 geo-storage

CO2 injection into

• Deep saline (aquifers)

• Depleted oil and gas fields

CO 2 ocean storage

• Dispersion from land based pipe or from moving ship with pipe to mid-depth.

• CO2 pond in the deep sea (3000m or deeper).

CO2

CO2

CO2

Subterranean Sequestration

CO2 Tanker Offshore BaseThermal Power Plant

CO2 Recovery Plant

Depth of3,000m

2,000~3,000m Underground

Injection PipeInjection Pipe

Ocean Sequestration(Shallow Sea)

Ocean Sequestration(Deep Sea)

32

2.3 Model constraints

The fundamental constraints for this model are to balance energy supply and demand,

including energy conservation over time and by energy sector, and to limit global CO2 emissions to

predetermined levels over time horizon. However, in order to give the model more realistic perspectives,

some additional constraints were added.

Major constraints are, first of all, a set of initial settings such as energy supply and plant

capacity that were considered so that the model result would be close to the current situation. Secondly,

increase and decrease limitations between points in time are given to facility capacity and volume of

use. Some additional restrictions are also added to types of energy transmission.

Initial conditions

[Energy constitution by country]

In order to make the model’s results closely resemble real world conditions, primary energy

supply at each node -- coal, oil, natural gas, nuclear, hydro and geothermal power, and biomass -- in

the year 2000 derived by the model must be within the range of 90% to 120% of IEA energy statistics.

[10]

[LNG and natural gas pipelines]

Natural gas transportation requires higher initial investment, and thus, if the appropriate initial

conditions are not provided, the model may give quite different results (production area, transportation

method, and so on). For this reason, real world natural gas pipelines and LNG transportation are

assigned to the corresponding links, and liquefaction and gasification plant capacities are also

assigned to corresponding nodes.

Numerous LNG projects and long distance pipeline projects are now proposed and under

consideration. Table 10 shows projects taken into account as initial values. Those projects are said to

be close to coming into existence, wi th strong support from local governments and the region.

2010 LNG Sakhalin ~ Japan

Australia ~ Southern China Indonesia ~ Southern China Middle East ~ India

Pipeline China West to East Pipeline Trans ASEAN Indonesian sector

2020 Pipeline Trans ASEAN Philippine sector

Table 10: Assumed initial projects at 2010 and 2020 in Asia.

33

Increase and decrease rate of capacity and volume

[Capacity constraints]

Energy facilities have a minimum lifespan of over 30 years, and once constructed, they can

usually be renovated. Also, fixed equipment, like pipelines, are used or replaced with maintenance.

Thus, all of the energy facilities will maintain their capacity until the end of the target period.

[Transmission volume constraints]

In this model, as the objective function is to minimize the total sum of the system cost, a

solution may present itself that could suddenly change the system. For example, if the total cost is

cheaper, it is mathematically possible to have a situation where the nearest natural gas field is emptied

within a certain time frame, say 10 years, and natural gas is then imported from a completely different

node during the following 10 years. However, land transmission pipelines are designed to be used at

maximum capacity throughout most of their lifetime, which limits the rate of decrease for pipeline flow to

0.8 times that of the previous period.

[LNG Long term contract]

Because of the expensive initial cost of LNG facility construction, LNG trading will not be turned

over completely to the free market. Most current LNG projects have long-term contracts of 20-30 years

that include the shipping destination the so-called “Take of Pay”. The future form of contracts is

uncertain. In this model, current contracts are emulated -- once started LNG transportation will continue

20 years at the same amount of trade, and, over the next time period, one half of the initial volume must

be maintained.

For other energy ocean transportation, the destination can be changed in the next time frame

with the restriction that the total amount of ocean transportation capacity of each energy sector must be

maintained in the next time period.

[Primary energy consumption growth and decrease rate constraints]

Just as with volume constraints, drastic changes in the use of the primary energy system can

also be handled in terms of minimum cost. For example, it is also mathematically viable to retain

existing CO2 polluting facilities in one time period, and, in the next period, construct natural gas based

facilities when natural gas usage experiences a large increase. However, energy systems and usage

have some inertial force.

In order to represent this, a set of limitations for growth and decrease rates for use at each

primary energy sector at each node or at each country is considered. When the upper limit of the

increase rate for the energy consumption growth is 4 times (plus 10 MTOE/year) that of the previous

time period, a lower limit of 0.5 is set for the decrease rate. An allowance of 10 MTOE/year is added in

34

order to avoid “no growth from an initial value of zero”. One reason for the decrease rate was the

inertial force for the energy system, but the versatility of energy sources, which is an important concept

for energy security, must also be considered.

Table 11 shows the warp up for the restrictions considered here.

Purpose for restriction Restriction • Facility remaining • PL transmission volume decrease • LNG remaining • Increase and decrease for PES

• 50 years for plants and transmission capacity • more than 0.8 times the previous time period • initial volume for 20 years and half of it ‘til 30th • within 0.5 to 4 times the previous period

Table 11: Assumed constraints for plant and transportation by time horizon.

Transmission versatile

As demand for energy in Asia increases in the future, importing oil and natural gas will become

necessary. Considering its versatility, importing natural gas is a very important and realistic issue from

both a political and business-oriented viewpoint, particularly for China and India, where increased

energy demands will make resources those countries scarce. For example, natural gas projects in

China consist of pipeline imports form Russia, long distance domestic gas transmission from western

development areas in China (called the “West to East Pipeline”), and LNG imports from Indonesia and

Australia.

In order to consider the potential for a natural gas network in Asia, two additional business and

security constraints are added for Japan, Korea, China and India to avoid unitary import regions.

• Imports from one region should be limited to a certain rate of total imports

• LNG should be used more than a certain rate of total imports

Table 12 shows the actual setting for these restrictions in numerical terms. These numbers are

defined based on current types of natural gas usage and geographical circumstances.

Japan has a high dependency on LNG because it has already constructed the downstream of

the LNG chain and advanced LNG technology, and it will continue to depend on LNG in the future.

Korea, like Japan, depends on LNG imports, but, unlike Japan, Korea already has a national trunk line,

and, if the Korean peninsula were to become stable, it could increase gas imports from Russia via

pipelines. India does not have much choice but to rely on the Middle East because of that region's vast

resources, so the upper limit of India's dependency on one region is set high.

35

Import region dependency Upper limit

LNG Dependency Lower limit

Japan 60% 70% Korea 60% 20% China 60% 20% India 70% 10% Import dependency on one

region should be less than this number.

LNG share of imports should be larger than this number.

Table 12: Diversification of natural gas import regions and methods.

2.4 Summary of model structure

In this chapter, the outline of the model is described. A summary of this chapter is as follows.

• World is represented by115 nodes (75 in Asia)

• Target duration is 2000-2050 and one model period is 10 years, for a total of 6 periods.

• Objective function is

∑∑∀= nodet

2050

2000

(production, transmission, conversion, consumption,

CO2 recovery and storage, energy saving)

• Fundamental data

Ø Primary energy resources

Ø Cost of everything from production to consumption

Ø Construction costs

• Constraints

Ø Primary energy consumption by sectors and by nodes in 2000

Ø Initial natural gas facilities

Ø Plant capacity usage

Ø Volume increase and decrease

• Purpose is to find an energy system that satisfies energy demand at each node and

minimizes the objective function.

36

Assumed amounts of fossil fuel resources

Resource categories for coal Category Number Status Site

Category 1 Proven Recoverable Reserves Anthracite / Bituminous Coal Category 2 Proven Recoverable Reserves Sub-bituminous Coal / Lignite Category 3 Additional Proven Recoverable Resources Anthracite / Bituminous Coal Category 4 Additional Proven Recoverable Resources Sub-bituminous Coal / Lignite Category 5 Additional Identified Reserves Anthracite / Bituminous Coal Category 6 Additional Identified Reserves Sub-bituminous Coal / Lignite

Resource categories for oil and natural gas Category number Status Probability in percentile Site

Category 1 Proven - Onshore/Offshore Category 2 Unproven More than F95 Onshore Category 3 Unproven F95~F50 Onshore Category 4 Unproven F50~F5 Onshore Category 5 Unproven More than F95 Offshore Category 6 Unproven F95~F50 Offshore Category 7 Unproven F50~F5 Offshore

Assumed coal reserves and resources by category and node (Unit: MTOE)

Sub-region Node Name Category 1Category 2Category 3Category 4Category 5Category 6 TotalEast Asia Beijing 3102 15143 25229 1778 7320 12195 64768East Asia Changsha 0 39 0 0 0 0 39East Asia Chengdu 0 0 0 0 0 0 0East Asia Chongqing 2205 7597 12301 1264 3672 5946 32985East Asia Dalian 190 1307 1893 109 632 915 5045East Asia East China sea 0 0 0 0 0 0 0East Asia Fuzhou 0 9 0 0 0 0 9East Asia Guangzhou 0 7 0 0 0 0 7East Asia Hainan 0 0 0 0 0 0 0East Asia Harbin 675 4640 6721 387 2243 3249 17914East Asia Hong Kong 0 0 0 0 0 0 0East Asia Jinan 1146 4894 6575 657 2366 3178 18816East Asia Kunming 2413 8312 13458 1383 4018 6505 36088East Asia Lanzhou 2287 21428 42884 1310 10357 20729 98995East Asia Nanking 668 2852 3831 383 1378 1852 10963East Asia Pusan 70 0 0 0 0 0 70East Asia Pyongyang 37 25 33 0 0 0 95East Asia Qingdao 1146 4894 6575 657 2366 3178 18816East Asia Seoul 63 0 0 0 0 0 63East Asia Shanghai 31 135 181 18 65 87 517East Asia Shenyang 190 1307 1893 109 632 915 5045East Asia Taipei 1 54 0 0 0 0 55East Asia Taiyuan 15591 76101 126785 8935 36784 61283 325479East Asia Tarim 2991 12775 17162 1714 6175 8296 49113East Asia Ulaanbaatar 0 0 0 0 0 0 0East Asia Wuhan 0 0 0 0 0 0 0East Asia Xian 2552 23911 47853 1462 11558 23130 110465East Asia Zhengzhou 0 0 0 0 0 0 0

Japan Fukuoka 0 0 0 0 0 0 0Japan Osaka 0 0 0 0 0 0 0Japan Sapporo 431 4116 0 0 0 0 4548Japan Tokyo 0 0 0 0 0 0 0SE Asia Bangkok 0 0 0 636 100 955 1691SE Asia Hanoi 82 0 0 0 0 0 82SE Asia Ho Chi Minn 0 0 0 0 0 0 0SE Asia Jakarta 0 0 0 0 0 0 0SE Asia Kalimantan 0 0 0 0 0 0 0SE Asia Kuala Lumpur 2 0 0 0 0 0 2SE Asia Manila 13 9 3 84 22 8 138SE Asia Medan 549 0 0 2236 0 3476 6261SE Asia Phnom Penh 0 0 0 0 0 0 0SE Asia Singapore 0 0 0 0 0 0 0SE Asia South China Sea 0 0 0 0 0 0 0SE Asia Vientiane 0 0 0 0 0 0 0SE Asia Yangon 1 0 0 0 0 0 1

Oceania Northeast Australia 5478 2167 8734 1946 366 9076 27767Oceania Northwest Australia 134 53 214 48 9 222 679Oceania Port Moresby 1 0 0 0 0 0 1Oceania Sydney 22653 8961 36118 8048 1514 37532 114826

South Asia Calcutta 6777 626 8045 65 0 0 15513South Asia Central India 27226 4009 54049 260 0 0 85545South Asia Delhi 351 22 198 3 0 0 574South Asia Dhaka 0 0 0 0 0 0 0South Asia Kabul 36 0 0 0 0 0 36South Asia Karachi 0 0 0 0 0 0South Asia Lahore 0 0 0 1049 0 0 1049South Asia Madras 3622 198 3313 35 0 0 7168South Asia Mumbai 1986 77 1678 19 0 0 3760

Sub-region Node Name Category 1Category 2Category 3Category 4Category 5Category 6 TotalMiddle East Baghdad 0 0 0 0 0 0Middle East Riyadh 0 0 0 0 0 0 0Middle East Teheran 106 0 0 0 0 0 106

FUSSR Almaty 17033 0 0 573 0 0 17606FUSSR Bering Sea 0 0 0 0 0 0 0FUSSR Eastern Black Sea 0 0 0 0 0 0 0FUSSR Turkmenistan 0 0 0 0 0 0 0FUSSR Kovykta 0 0 0 0 0 0 0FUSSR Kiev 9004 3001 2079 6299 2100 1444 23928FUSSR Moscow 2510 1363 52427 865 136 16402 73703FUSSR Timan Pechora 1875 1018 39162 0 0 0 42055FUSSR Novosibirsk 17507 9510 365724 34622 5461 656823 1089647FUSSR Sakhalin 0 0 0 0 0 0 0FUSSR Tashkent 549 0 0 573 0 0 1123FUSSR Vladivostok 801 435 16739 2044 322 38768 59109FUSSR West Kazakhstan 0 0 0 0 0 0 0FUSSR Yakutsk 4279 2324 89378 393 62 7455 103891FUSSR Tyumen 0 0 0 0 0 0 0

Europe Amsterdam 273 499 755 0 0 0 1528Europe Berlin 14500 12084 112374 9147 7502 12 155619Europe Bucharest 46 0 1 4816 204 431 5497Europe Greenland 0 0 0 66 0 36 101Europe Istanbul 210 0 117 504 1317 22 2170Europe London 627 0 0 106 0 0 734Europe Madrid 102 756 756 147 182 194 2136Europe Mediterranean Sea 0 0 0 0 0 0 0Europe North Sea 0 0 0 0 0 0 0Europe Paris 61 318 32 8 37 18 473Europe Rome 0 0 0 11 14 4 29Europe Stockholm 0 0 0 3 35 13 50Europe Warsaw 8466 29009 2840 2438 3604 1931 48288Africa Cairo 0 0 0 8 2 19 28Africa Cape Town 32187 38325 2908 0 9 0 73430Africa Casablanca 25 6 0 0 8 0 39Africa Harare 3231 1755 125230 20 0 0 130237Africa Kinshasa 48 0 0 0 0 0 48Africa Lagos 50 0 0 61 0 0 111Africa Madagascar Island 0 0 0 0 0 0 0Africa Nairobi 110 0 0 0 0 0 110Africa Tripoli 0 0 0 0 0 0 0

N America Alaska 183 211 749 1395 781 6323 9641N America Calgary 3101 1324 17910 1548 4757 12817 41456N America Chicago 43083 49661 176513 2432 1362 11023 284074N America Houston 2902 3345 11889 6021 3373 27293 54823N America Los Angels 493 568 2018 30688 17191 139101 190058N America Mexico City 473 0 0 145 0 0 617N America Montreal 0 0 0 0 0 0 0N America New York 17777 20492 72834 0 0 0 111103N America Newfoundland 0 0 0 0 0 0 0N America Salt Lake City 5003 5767 20498 18537 10384 84022 144210S America Buenos Aires 0 0 0 47 0 0 47S America Caracas 263 466 1334 0 0 0 2063S America Lapas 1 0 1 0 0 0 1S America Patagonia 17 0 0 412 0 0 429S America Quito 4026 0 0 160 0 0 4187S America San Paulo 0 0 0 4710 2019 3019 9749

World Total 295624 387904 1539990 163392 152437 1209894 3749242

37

Assumed oil (left) and natural gas (right) reserves and resources by category and node (Unit: MTOE)

Sub-region Node Name Category 1Category 2Category 3Category 4Category 5Category 6Category 7 TotalEast Asia Beijing 0 0 0 0 0 0 0 0East Asia Changsha 0 0 0 0 0 0 0 0East Asia Chengdu 10 2 4 0 0 0 0 16East Asia Chongqing 0 0 0 0 0 0 0 0East Asia Dalian 0 0 0 0 0 0 0 0East Asia East China Sea 0 0 0 0 250 191 735 1176East Asia Fuzhou 0 0 0 0 0 0 0 0East Asia Guangzhou 0 0 0 0 0 0 0 0East Asia Hainan 90 0 0 0 29 29 103 252East Asia Harbin 503 149 128 272 0 0 0 1052East Asia Hong Kong 0 0 0 0 44 29 103 176East Asia Jinan 2043 290 508 246 0 0 0 3086East Asia Kunming 0 0 0 0 0 0 0 0East Asia Lanzhou 0 0 0 0 0 0 0 0East Asia Nanking 0 0 0 0 4 3 15 22East Asia Pusan 0 0 0 0 0 0 0 0East Asia Pyongyang 0 0 0 0 0 0 0 0East Asia Qingdao 0 0 0 0 0 0 0 0East Asia Seoul 0 0 0 0 0 0 0 0East Asia Shanghai 0 0 0 0 0 0 0 0East Asia Shenyang 0 0 0 0 0 0 0 0East Asia Taipei 0 0 0 0 0 0 0 0East Asia Taiyuan 0 0 0 0 0 0 0 0East Asia Tarim 1283 842 1314 748 0 0 0 4188East Asia Ulaanbaatar 0 107 78 373 0 0 0 559East Asia Wuhan 0 0 0 0 0 0 0 0East Asia Xian 88 12 19 0 0 0 0 118East Asia Zhengzhou 0 0 0 0 0 0 0 0

Japan Fukuoka 0 0 0 0 0 0 0 0Japan Osaka 0 0 0 0 0 0 0 0Japan Sapporo 8 0 0 0 0 0 0 8Japan Tokyo 0 0 0 0 0 0 0 0SE Asia Bangkok 14 34 25 118 44 44 132 411SE Asia Hanoi 0 0 0 0 0 0 0 0SE Asia Ho Chi Minn 0 0 0 0 106 104 304 515SE Asia Jakarta 224 51 22 103 0 0 0 400SE Asia Kalimantan 114 0 0 0 118 118 412 761SE Asia Kuala Lumpur 0 0 0 0 240 231 823 1294SE Asia Manila 41 0 0 0 118 103 221 482SE Asia Medan 27 191 118 603 15 15 44 1012SE Asia Phnom Penh 0 0 0 0 0 0 0 0SE Asia Singapore 0 0 0 0 0 0 0 0SE Asia South China Sea 0 42 111 201 435 989 1622 3400SE Asia Vientiane 0 0 0 0 0 0 0 0SE Asia Yangon 37 74 59 323 0 0 0 493

Oceania Northeast Australia 10 0 0 0 14 14 41 79Oceania Northwest Australia 392 20 32 51 406 819 1397 3118Oceania Port Moresby 42 147 132 456 0 0 0 777Oceania Sydney 60 7 7 28 71 87 215 475

South Asia Calcutta 0 29 41 73 1 4 9 158South Asia Central India 0 0 0 0 0 0 0 0South Asia Delhi 0 0 0 0 0 0 0 0South Asia Dhaka 3 18 16 40 0 0 0 77South Asia Kabul 0 0 0 0 0 0 0 0South Asia Karachi 14 0 0 0 0 0 0 14South Asia Lahore 24 15 15 29 0 0 0 83South Asia Madras 0 0 0 0 41 28 99 168South Asia Mumbai 0 14 40 78 90 182 243 647

Middle East Baghdad 29661 2333 4717 6897 160 304 455 44527Middle East Riyadh 50947 5827 11359 18055 996 1790 2641 91615Middle East Teheran 12340 1935 4025 6292 792 1628 2571 29581

FUSSR Almaty 0 294 147 735 0 0 0 1176FUSSR Bering Sea 0 0 0 0 0 0 0 0FUSSR Eastern Black Sea 40 20 40 67 5 11 23 206FUSSR Turkmenistan 157 173 289 407 397 1001 1519 3944FUSSR Kovykta 0 0 0 0 0 0 0 0FUSSR Kiev 83 42 220 330 0 0 0 675FUSSR Moscow 0 0 1 1 0 0 0 2FUSSR Timan Pechora 817 331 343 600 253 637 1261 4242FUSSR Novosibirsk 394 172 492 987 0 0 0 2045FUSSR Sakhalin 519 11 29 52 304 647 1131 2693FUSSR Tashkent 136 88 397 618 0 0 0 1239FUSSR Vladivostok 0 0 0 0 0 0 0 0FUSSR West Kazakhstan 745 927 1634 2859 930 2274 4154 13524FUSSR Yakutsk 0 0 0 0 0 0 0 0FUSSR Tyumen 4912 2584 5050 8453 403 1221 2873 25496

Europe Amsterdam 15 1 2 3 0 0 0 21Europe Berlin 61 3 6 11 0 0 0 82Europe Bucharest 244 68 106 187 0 0 0 605Europe Greenland 0 0 146 188 0 7164 9205 16703Europe Istanbul 42 33 66 98 55 96 124 515Europe London 0 0 1 1 14 14 55 85Europe Madrid 2 0 0 0 1 0 0 3Europe Mediterranean Sea 0 0 0 0 0 131 405 535Europe North Sea 2193 0 0 0 762 1410 2828 7194Europe Paris 15 0 0 0 0 0 0 15Europe Rome 86 7 44 109 2 5 9 262Europe Stockholm 147 0 0 0 472 1507 3257 5384Europe Warsaw 34 43 67 172 0 0 0 316Africa Cairo 442 104 169 315 175 379 575 2159Africa Cape Town 4 0 0 0 13 25 76 119Africa Casablanca 0 28 55 177 1 7 21 290Africa Harare 745 78 130 0 7 3 17 980Africa Kinshasa 577 119 196 413 1291 2753 4311 9659Africa Lagos 3169 1278 1340 1674 1568 2343 2782 14155Africa Madagascar Island 0 83 83 206 0 0 0 371Africa Nairobi 0 199 183 475 43 29 144 1073Africa Tripoli 5366 693 1546 2698 108 172 596 11180

N America Alaska 710 401 896 1430 413 422 816 5088N America Calgary 4090 72 103 156 344 248 647 5659N America Chicago 91 111 187 307 0 0 0 697N America Houston 2201 834 1043 1466 0 1143 0 6688N America Los Angels 659 197 409 664 0 186 0 2115N America Mexico City 3979 414 823 1315 539 1173 2305 10547N America Montreal 215 0 0 0 28 14 41 298N America New York 14 5 10 19 0 33 0 81N America Newfoundland 2478 0 0 0 129 241 581 3428N America Salt Lake City 257 351 674 1031 0 0 0 2313S America Buenos Aires 0 4 4 14 19 41 100 182S America Caracas 10121 846 1583 2616 499 2500 5658 23823S America Lapas 18 173 366 992 0 0 0 1550S America Patagonia 399 112 222 338 109 785 2393 4359S America Quito 694 383 749 1593 69 170 261 3919S America San Paulo 1012 158 138 421 1310 5438 9681 18158

World Total 145858 23582 42759 69186 14234 40934 70038 406591

FUSSR Almaty 0 54 8 208 0 0 0 270FUSSR Bering Sea 0 0 0 0 0 0 0 0FUSSR Eastern Black Sea 396 57 98 154 52 74 108 939FUSSR Turkmenistan 4072 274 666 835 474 1258 1871 9450FUSSR Kovykta 1774 244 244 1948 0 0 0 4210FUSSR Kiev 967 180 415 529 0 0 0 2090FUSSR Moscow 8 3 3 4 0 0 0 19FUSSR Timan Pechora 10752 275 390 615 1543 4500 7435 25508FUSSR Novosibirsk 2162 451 982 1533 0 0 0 5128FUSSR Sakhalin 2791 19 51 86 566 1009 2100 6621FUSSR Tashkent 8 822 1227 3424 0 0 0 5480FUSSR Vladivostok 0 0 0 0 0 0 0 0FUSSR West Kazakhstan 1583 1589 3498 5898 775 2041 3743 19127FUSSR Yakutsk 0 0 0 0 0 0 0 0FUSSR Tyumen 23517 1613 3634 6681 2651 6396 11303 55795

Europe Amsterdam 1523 18 26 35 0 0 0 1603Europe Berlin 314 105 150 199 0 0 0 768Europe Bucharest 401 49 102 188 8 11 17 776Europe Greenland 0 0 39 58 0 1934 2834 4865Europe Istanbul 8 5 11 20 2192 2776 8791 13804Europe London 17 0 0 1 0 0 0 18Europe Madrid 1 0 0 0 0 0 0 1Europe Mediterranean Sea 0 0 0 0 0 604 1581 2186Europe North Sea 1657 0 0 0 357 1172 2480 5667Europe Paris 12 0 0 0 0 0 0 12Europe Rome 197 113 178 307 41 60 94 990Europe Stockholm 83 0 0 0 942 3693 7431 12149Europe Warsaw 211 125 131 306 0 0 0 773Africa Cairo 930 87 159 358 333 619 1280 3766Africa Cape Town 19 5 5 19 65 106 233 452Africa Casablanca 1 65 126 381 1 5 15 595Africa Harare 161 75 71 202 24 24 54 612Africa Kinshasa 108 179 205 375 527 1294 2354 5042Africa Lagos 3193 679 703 1019 801 1210 1758 9363Africa Madagascar Island 2 49 44 80 49 44 80 348Africa Nairobi 99 303 196 628 177 128 658 2188Africa Tripoli 5086 389 853 1534 655 703 2952 12172

N America Alaska 237 596 1071 1648 609 794 1033 5987N America Calgary 1104 159 201 305 974 852 1218 4813N America Chicago 129 93 111 250 0 0 0 582N America Houston 2805 2097 1231 1457 0 2186 0 9776N America Los Angels 92 84 217 374 0 23 0 790N America Mexico City 735 738 884 1485 160 427 968 5398N America Montreal 116 0 0 0 0 219 170 506N America New York 169 38 31 47 0 131 0 416N America Newfoundland 336 0 0 0 195 282 652 1464N America Salt Lake City 644 319 415 695 0 0 0 2073S America Buenos Aires 0 17 16 65 22 43 112 276S America Caracas 3967 648 1160 2450 468 1974 4815 15483S America Lapas 106 374 535 4311 0 0 0 5327S America Patagonia 675 190 385 573 121 569 1646 4159S America Quito 477 258 324 1007 28 75 133 2302S America San Paulo 194 167 136 642 840 3358 6320 11657

World Total 122671 24473 40982 74330 21286 49649 92807 426198

Sub-region Node Name Category 1Category 2Category 3Category 4Category 5Category 6Category 7 TotalEast Asia Beijing 0 0 0 0 0 0 0 0East Asia Changsha 0 0 0 0 0 0 0 0East Asia Chengdu 164 63 186 186 0 0 0 599East Asia Chongqing 0 0 0 0 0 0 0 0East Asia Dalian 0 0 0 0 0 0 0 0East Asia East China Sea 52 0 0 0 404 404 1348 2209East Asia Fuzhou 0 0 0 0 0 0 0 0East Asia Guangzhou 0 0 0 0 0 0 0 0East Asia Hainan 209 0 0 0 458 404 1186 2258East Asia Harbin 49 66 77 102 0 0 0 294East Asia Hong Kong 0 0 0 0 27 27 81 135East Asia Jinan 351 75 180 158 0 0 0 764East Asia Kunming 0 0 0 0 0 0 0 0East Asia Lanzhou 0 0 0 0 0 0 0 0East Asia Nanking 0 0 0 0 0 0 0 0East Asia Pusan 0 0 0 0 0 0 0 0East Asia Pyongyang 0 0 0 0 0 0 0 0East Asia Qingdao 0 0 0 0 0 0 0 0East Asia Seoul 0 0 0 0 0 0 0 0East Asia Shanghai 0 0 0 0 0 0 0 0East Asia Shenyang 0 0 0 0 0 0 0 0East Asia Taipei 159 0 0 0 0 0 0 159East Asia Taiyuan 0 0 0 0 0 0 0 0East Asia Tarim 377 846 1669 1655 0 0 0 4548East Asia Ulaanbaatar 0 0 0 0 0 0 0 0East Asia Wuhan 0 0 0 0 0 0 0 0East Asia Xian 146 0 1 0 0 0 0 147East Asia Zhengzhou 0 0 0 0 0 0 0 0

Japan Fukuoka 0 0 0 0 0 0 0 0Japan Osaka 0 0 0 0 0 0 0 0Japan Sapporo 0 0 0 0 0 0 0 0Japan Tokyo 0 0 0 0 0 0 0 0SE Asia Bangkok 0 94 94 270 256 229 809 1752SE Asia Hanoi 0 0 0 0 0 0 0 0SE Asia Ho Chi Minn 0 0 0 0 40 40 189 270SE Asia Jakarta 189 35 32 102 0 0 0 359SE Asia Kalimantan 1050 27 27 54 148 148 323 1778SE Asia Kuala Lumpur 0 0 0 0 359 356 795 1510SE Asia Manila 140 0 0 0 0 0 0 140SE Asia Medan 159 81 81 216 108 108 243 994SE Asia Phnom Penh 0 0 0 0 0 0 0 0SE Asia Singapore 0 0 0 0 0 0 0 0SE Asia South China Sea 523 105 230 382 653 1418 2355 5667SE Asia Vientiane 0 0 0 0 0 0 0 0SE Asia Yangon 251 22 19 59 0 0 0 351

Oceania Northeast Australia 252 365 244 852 0 0 0 1713Oceania Northwest Australia 928 28 53 57 828 1721 2700 6316Oceania Port Moresby 317 687 534 1502 0 0 0 3040Oceania Sydney 99 20 18 63 64 118 292 674

South Asia Calcutta 0 65 158 270 35 97 174 799South Asia Central India 0 0 0 0 0 0 0 0South Asia Delhi 0 0 0 0 0 0 0 0South Asia Dhaka 252 162 135 450 0 0 0 998South Asia Kabul 6 0 0 0 0 0 0 6South Asia Karachi 293 0 0 0 0 0 0 293South Asia Lahore 268 377 297 485 0 0 0 1428South Asia Madras 0 0 0 0 22 22 110 153South Asia Mumbai 0 19 47 90 82 173 265 675

Middle East Baghdad 4470 1028 2080 3113 132 195 296 11315Middle East Riyadh 18347 5422 11183 16981 882 1569 2291 56675Middle East Teheran 19782 1277 2703 4350 1139 2027 3109 34387

38

3. MODEL DATA SETTINGS At the end of the 20th century, people in Asia had come to enjoy stability and economic growth,

and Asia is now trying to achieve greater economic growth in the 21st century in order to join the ranks

of developed countries through regional stability and global relationships. This model analysis, which is

a Base Case, considers a world in which people choose steady economic growth and concerted global

action toward regional and global environmental issues. Initially, an energy transportation system is

considered that creates the Base Case world mathematically, and then, from these results, we would

like to describe the future role of natural gas.

We know that, in the real business world, energy systems are defined based on a combination

of geopolitics, supplier and consumer speculation, and national policies. This is why mathematically

induced energy systems may include questionable answers or messages, but we would like to use the

model as a tool for examining the future of natural gas in Asia by comparing the existing world with the

future images derived from the calculation results, which may still include assumptions and

uncertainties.

In this section, a Base Case scenario that can be used as an index case for other analysis is

explained from the following standpoints.

1. Geographical coverage for main analysis

2. Exogenous demand scenario and data

3. Model data settings

3.1 Regions to be analyzed

Although this model can analyze the entire world, this analysis focused on, Asia and

neighboring regions. Asia is divided into four sub-regions -- Northeast Asia, Southeast Asia, Oceania,

and South Asia -- to provide a more precise analysis. As such, Asia in this analysis is defined so as to

cover these four sub-regions. The names of the countries and regions covered by each sub-region are

listed below and Figure 16 indicates these sub-regions by color.

Northeast Asia: China (including Chinese Taipei, Hong Kong China), Japan, Korea,

Korea DPR, and Mongolia

Southeast Asia: Brunei, Cambodia, Indonesia, Laos, Malaysia, Myanmar, Papua New

Guinea, Philippines, Singapore, Thailand, and Vietnam

Oceania: Australia, New Zealand, and the Pacific Islands

South Asia: Bangladesh, Bhutan, India, Nepal, Pakistan, and Sri Lanka

39

Figure 16: Regions to be analyzed.

3.2 Demand scenario and data

IPCC Scenarios

In this analysis, we consider a world in which global economic growth particularly in Asia,

drives the world to take action regarding global climate issues and to build a sustainable future.

Consequently, we would like to describe the development of Asia’s energy infrastructure and the role of

natural gas.

IPCC has made public its well-known emission scenarios for a hundred years as

groundbreaking research on global climate change during world economic growth. (Box 3 and [11])

Based on IPCC emission scenarios, IGU has also performed analysis by focusing on the role of natural

gas for a sustainable future. [12]

In the IPCC Emission Scenarios, four different scenario storylines are prepared named “A1”,

“A2”, “B1”, and “B2”, which are divided based on two axes axes -- whether the world becomes

“economic or environment oriented” and whether the world solves problems “globally or regionally”.

In these scenarios, the world is divided into four regions based on economic growth and energy

demand prospects to 2100 for each region are prepared. In order to incorporate this with the IPCC

scenarios, IPCC’s regional energy demands must be recompiled to 115 nodes in this model. In order to

do this, a total energy demand prospect is created by country for every 10 years until 2050 based on

the IEA’s energy demand data by country, prospects for the population, and GDP development. IPCC’s

sectional and regional demands are divided based on this energy demand prospect and energy

demand data for 115 nodes are defined.

40

For this Base Case scenario, the B2 scenario was chosen as a reference in order to assume

moderate economic and energy demand growth of the world.

Box 3 IPCC Emission Scenarios

“Special Report on Emission Scenarios” by IPCC

The Special Report on Emission Scenario (SRES) from IPCC,

considers four different future scenarios. In this report, each

scenario is explained with numbers such as populations, GDPs,

final energy consumptions for the world, and numbers for four

divided regions. The data set makes it possible for researchers

to discuss issues based on the common scenario stories and

common assumptions.

The outlines for these four basic scenario storylines are as

follows.

A1 Storyline

The A1 storyline and scenario family describes a future world of very rapid economic growth,

low population growth, and the rapid introduction of new and more efficient technologies. Major

underlying themes are convergence among regions, capacity building and increased cultural and

social interactions, with a substantial reduction in regional differences in per capita income. The A1

scenario family develops into four groups that describe alternative directions of technological change

in the energy system.

A2 Storyline

The A2 storyline and scenario family describes a very heterogeneous world. The underlying

theme is self-reliance and preservation of local identities. Fertility patterns across regions converge

very slowly, which results in high population growth. Economic development is primarily regionally

oriented and per capita economic growth and technological change are more fragmented and slower

than in other storylines.

B1 Storyline

The B1 storyline and scenario family describes a convergent world with the same low

population growth as in the A1 storyline, but with rapid changes in economic structures toward a

service and information economy, with reductions in material intensity, and the introduction of clean

and resource-efficient technologies. The emphasis is on global solutions to economic, social, and

environmental sustainability, including improved equity, but without additional climate initiatives.

41

B2 Storyline

The B2 storyline and scenario family describes a world in which the emphasis is on local

solutions to economic, social, and environmental sustainability. It is a world with moderate population

growth, intermediate levels of economic development, and less rapid and more diverse technological

change than in the B1 and A1 storylines. While the scenario is also oriented toward environmental

protection and social equity, it focuses on local and regional levels.

Source: IPCC Emission Scenarios

Demand assumptions

We have examined the B2 scenario story carefully, and from our knowledge, “increasing

motorization”, the phrase that was emphasized in B2, is already becoming a concern in many countries.

In order to solve the problem regarding both global and local environmental issues, shifting to natural

gas vehicles (NGV), including fuel cell vehicles, is ongoing.

According to the report by WOC 6.3 from the World Gas Conference 2000, Nice [13], the NGV

market can grow to gain up to 10-25 % of the vehicle market share in 10 years with support from the

government, an increase in the number of fueling stations by the gas industry, and enforced emission

standard. At the same time, according to energy statistics from IEA [10], 47.7% of the world’s liquid

energy or 30.4% of Asia’s liquid energy, in 2000 was consumed for motor vehicles, and taking these

together, 3-12% of liquid demand can be shifted to gaseous demand.

Based on this rough calculation, an assumption is made that gaseous energy can substitute

5% of liquid demand (or almost 10% of transportation use) in 2010 and, consequently, 25% of liquid

demand in 2050. Furthermore, an ultimate fuel cell vehicle can run with only 70% of the energy

consumption of the existing gasoline vehicles, and it is assumed that this efficiency can also be

achieved in 2050.

These kinds of demand shifts between energy sections arising from technology improvements

and efficiency increases cannot be assumed automatically in the model, so a direct demand

manipulation (shift) is necessary. For this purpose, B2 demand has been modified slightly to something

between liquid demand and gaseous demand. Although this assumption appears too ambitious for the

gas industry, we chose this to find the potential of natural gas.

The basic formulation for the demand shift from liquid to gaseous demand is shown in Table 13

and this formula is applied to each node and time. The final energy (shifted) demand by section

42

(gaseous, liquid, solid and electricity demand) for the world, Asia and Asian sub regions are shown in

Figure 17.

Y2000 Y2010 Y2020 Y2030 Y2040 Y2050 Original Demand Liquid a0 a1 a2 a3 a4 a5 Gaseous b0 b1 b2 b3 b4 b5 Co efficiency for FCEV (NGV) efficiency improvement Y2000=1 1.0 0.94 0.88 0.82 0.76 0.70 Shifted Demand Liquid 1.00xa0 0.95xa1 0.90xa2 0.85xa3 0.80xa4 0.75xa5 Gaseous b0 b1+0.047xa1 b2+0.088a2 b3+0.123a3 b4+0.152xa4 b5+0.175xa5

Table 13: Shift from liquid to gaseous demand.

a) World

0

2000

4000

6000

8000

10000

12000

14000

2000 2010 2020 2030 2040 2050

ElecSolidLiquidGaseous

b) Asia

0

1000

2000

3000

4000

5000

6000

2000 2010 2020 2030 2040 2050


c) Northeast Asia

0

1000

2000

3000

4000

5000

6000

2000 2010 2020 2030 2040 2050


d) Southeast Asia

0

200

400

600

800

1000

2000 2010 2020 2030 2040 2050


e) Oceania

0

50

100

150

200

250

2000 2010 2020 2030 2040 2050


f) South Asia

0

500

1000

1500

2000

2000 2010 2020 2030 2040 2050


Figure 17: Assumed demand for Base Case. (MTOE/year)

b+ax0.05x0.94 -ax0.05 b+ax0.20x0.76 -ax0.20

43

3.3 Other data

This section is to confirm the important data previously described.

Resources

Fossil fuel resources are categorized and assigned to each node and the amounts are based

on conventional resources from USGS analysis [1]. Their production costs are assumed based on the

report by Rogner [3]. Total world resources for coal, oil, and natural gas are 3749 GTOE, 407 GTOE,

and 426 GTOE, respectively, and oil is assumed to be located mainly in the Middle East, and natural

gas resources are assumed to be in Russia, the Middle East, and North America. (Figure 18) Thus,

considering natural gas transportation to Asia, analysis on how regional production in Asia and

transmission from outside Asia are combined is quite important.

Coal3779

GTOE

Oil

407GTOE

NaturalGas

426GTOE

Figure 18: Assumed world fossil fuel resources.

Transmission

In the Base Case, no barrier for international energy trade is considered. This means that

transmission cost between two nodes by land link is defined only by the amount of flow and

transmission distance. The reason given is that accession of China and India to the WTO in 2001 will

drive this area into an area-wide relationship at the first stage, and, eventually, a global economy. This

world is said to be the ultimate world of the “Energy Charter Treaty” originally started in Europe.

Energy related technologies

In this analysis, highly efficient fuel cell systems, including stationary and mobile use, are

assumed to be achieved based on the current aggressive research and development. As a

representative number for the large scale generation system, the total system efficiency is supposed to

grow up to 60% with SOFC/GT hybrid systems in 2050. And, regarding mobile fuel systems, a fuel cell

vehicle with efficiency 30% better than current gasoline based vehicles is assumed to be achieved.

44

Discount Rate

In this mode, the total system cost is the sum of the cost for each time period, discounted to the

value for the year 2000. The discount rate used here is 5%. Usually a little higher discount rate is used

when business risks are calculated, but in this model, this rate is applied to evaluate the value change

of things over time.

CO 2 emission limit

In order to control global warming within the model, global CO2 emission limits are provided

exogenously. This set of upper limits for CO2 emissions at each time point is defined in order to stabilize

the CO2 concentration below 550 ppmV, an agreed index, during the 21st century under the B2 scenario.

This limitation set is obtained from the work of GES [12], which uses a global energy supply

optimization model “LDNE21” developed by the University of Tokyo.

The data set over 100 years for CO2 emission limits that was obtained from GES and the CO2

concentration curve during this century are shown in Figure 19. The limitation data set until 2050 is

applied in our model for the Base Case.

a) CO2 emissions (Gt-C/Year)

0

2

4

6

8

10

12

14

2000 2020 2040 2060 2080 2100

CO2 Emissions

b) World CO2 concentration (ppmV)

200

300

400

500

600

2000 2020 2040 2060 2080 2100

CO2 Concentration

Target

280ppmV Before Industrial Revolution

Figure 19: Global CO2 emission limits and the global CO2 concentration.

Regarding the Kyoto Protocol, although the protocol is going to take effect in a great number of

ratified countries, the model considers a more precise, 50-year long mechanism for the first

commitment period, and development toward the second period is necessary in order to implement the

mechanism into the model. Furthermore, other GHGs are not currently considered in the model, which

does not deals with the Kyoto Protocol.

45

4. BASE CASE RESULTS

Although natural gas resources are widely available in the world, as seen previously on Figure

18 the main resource-rich areas are the Middle East and Russia, which are near Asia. Within Asia,

additional resource exploration can be expected in Southeast Asia and Oceania. In this chapter,

analysis will be carried out on how natural gas resources can be transported from these production

regions to regions of growing demand, which are Northeast Asia, led by China, and South Asia, led by

India. The role of natural gas, as well as volume, usage, and other aspects, are also examined.

The Base Case Scenario is applied to the Asia Energy Infrastructure Model and analysis is

carried out based on its solution. Viewpoints of the results are as follows.

l Natural gas transportation

Ø Development of natural gas transportation system

Ø Transportation method

Ø Suppliers

l Roles of natural gas

Ø Primary energy supply and the role of natural gas in PES

Ø Role of natural gas in power generation

Ø CO2 emission reduction

4.1 Natural gas transportation

In this section, a detailed analysis of natural gas transportation is done. This analysis of the

development of natural gas infrastructure has become available with this model because of the precise

setting in this region. A qualitative analysis of the development the of natural gas infrastructure is

followed by a quantitative analysis of both LNG transportation, which is currently the main form of

transportation, and pipeline transportation, which will be on the rise in the future. The role of suppliers is

also mentioned.

Development of natural gas infrastructure in Asia

Figure 20 shows mapped information of the current long distance natural gas transportation in

Asia based on the region definition in the model. Recently, several projects have been established in

Southeast Asia, and because they are still the pipelines connecting the source with demand they

cannot be displayed with the model resolution. One of the traits of natural gas transportation in Asia is

that it is quite limited and natural gas is used only around the source region.

46

Natural Gas(LNG)[MTOE/yr]

50 - 10020 - 5010 - 20

5 - 100 - 5

Natural Gas(PL) [MTOE/y]

50 - 10020 - 5010 - 20

5 - 100 - 5

Figure 20: Natural gas transportation in 2000.

This subsection explains the development of natural gas transportation in Asia over a 50-year

period. Although the model results are themselves the combination of volume carried between two

nodes, data expressed on the map now gives intuitive views on the evolvement of infrastructure. This is

a quantitative analysis, but it can give qualitative views for the change of relationships between

production area and consumption area.

Figure 21 shows the model calculation results for natural gas infrastructure in 2020, 2030, and

2050. Please note that, because various natural gas land transportation routes in the Japan area are

proposed by several organizations, some routes are displayed in dotted lines as alternative choices.

47

a) 2020

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100 - 50 - 10020 - 5010 - 205 - 100 - 5

Figure 21: Development of natural gas infrastructure focused in Asia.

48

In 2020, LNG transportation maintains the current situation primarily because of the Take or

Pay, and Oceania has trade across the Pacific. In this time frame, high-capacity natural gas pipelines

connecting production areas and neighboring consumption areas are constructed. Moreover, northern

areas of Northeast Asia and South Asia, where there are fewer natural gas resources, are connected

with also high-capacity pipeline networks from East Siberia and Sakhalin, and the Middle East,

respectively.

In 2030, natural gas networks have been enhanced since 2020, and, in 2050, natural gas

supply flow from West Siberia can be seen as part of a huge network in Northeast Asia. The pipeline is

connected to China’s domestic pipeline and supports demand in central China. Also, coastal nodes in

Northeast Asia are major LNG importers from the Middle East.

Since 2030 in Southeast Asia, a natural gas market is created that includes China, and is

connected to the China market. Southeast Asia and Oceania supply natural gas to their own regions,

and also export LNG to Northeast Asia and the Pacific market.

Western South Asia is supplied from the Middle East pipeline and eastern areas are supplied

by LNG from the Middle East, and, in 2050, a broad network extending from the Middle East and

Central Asia to eastern India is expanded from the pipeline network of 2030.

Observation – Natural gas infrastructure

2020 and 2030

Infrastructure in 2030 is the expansion of which in 2020.

Northeast Asia

1. Far east Russia to northern Northeast

Asia

2. Expansion of domestic infrastructure

and LNG projects to China

Southeast Asia, Oceania

3. Expansion of regional infrastructure

such as TAGP

4. Connection to Chinese domestic

network by 2030

South Asia

5. Long distance pipeline to western India and LNG to eastern India from the Middle East

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& o the r R e g i o n s


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100 -50 - 10020 - 5010 - 20

5 - 100 - 5


100 - 50 - 10020 - 5010 - 20

5 - 100 - 5

Natural gas in 2030

1

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100 -50 - 10020 - 5010 - 20

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5 - 100 - 5

Natural gas in 2030

1

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49

2050

Infrastructure increases in volume, and area.

Northeast Asia

1. Connection from east Siberia

2. China pipeline connecting north to

south

Southeast Asia and Oceania

3. Expansion of pipeline capacity

4. Extension from PNG to Australia

South Asia

5. New supply from Central Asia to India

* Maps are from Figure 20.

Development of LNG transportation to Asia

Currently, Asia has been received three quarters of the world’s LNG trade. As seen in the

previous figures, in order to support the increasing demand in Asia, LNG supply will steadily increase

as a method of importing gas from the Middle East and also as a method of dispersing importing areas

out of energy security considerations. Here, an analysis of LNG transportation to Asia is made in order

to examine the amount of trade by receiving countries while comparing the previous results from the

infrastructure map.

Figure 22 shows the LNG import volume by receiving countries in the Base Case. From the

model results, current LNG destination countries (areas), like Japan, Korea, and Chinese Taipei, and

countries proposing projects, like India and China, will become future importers.

Japan and Korea, which already have developed LNG chains and an energy demand structure

that will not change drastically, will keep their LNG amounts at current levels. China and India, where

substantial natural gas demand increases are expected, will greatly increase import volume. Many of

China's big cities are located within 1000 km of the coast, and supply will be combined with interior

domestic gas, Russian pipeline gas and imported LNG, as seen in Figure 21. India, which is located

next to the Middle East and Central Asia is mainly relying on pipeline gas (as shown in Figure 21), but

increases its imports of LNG right after 2030.

Based on these results, in 2050, LNG transportation to Asia will increase to five times current

LNG trade to Northeast Asia, the current total of which is approximately 70 Mt-LNG. This is equivalent

to an annual rate increase of 3.4%. Also this means, in 2050, approximately 5,000 LNG tankers, each

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R e g i o n s


uu 100

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100 -50 - 10020 - 5010 - 20

5 - 100 - 5


100 - 50 - 10020 - 5010 - 20

5 - 100 - 5

Natural gas in 2050

1

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100 - 50 - 10020 - 5010 - 20

5 - 100 - 5

Natural gas in 2050

1

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50

with a capacity of 70,000t-LNG, will sail to eastern South Asia and Northeast Asia every year. As for

Northeast Asia, importing facilities could double within 30 years (and most of the facilities should be

constructed in China), and the next 20 years will be a period in which most additional LNG construction

will take place in South Asia

0

100

200

300

400

500

2000 2010 2020 2030 2040 2050

Mt-

LNG

/yr

IndiaChinaKoreaJapan

Figure 22: Development of LNG transportation to Asian countries. (Mt-LNG/year)

Observation - LNG in Asia

• LNG transportation to Asia will increase to five times current levels

• Most additional facilities should be constructed in China for the next 30 years

• After 2030, center of construction shift to South Asia

Box 4 LNG trade to Japan

The current number of LNG trades destined for Japan is 14, and the total number of LNG tankers is 65.

The main class of cargo tonnage, or capacity, is 70,000 ton-LNG or 130,000m3. One round trip takes 15

days (from Southeast Asia) to 30 days (from Middle East) and, if 330 yearly operating days are

assumed, 1,100 ships come to Japan every year based on shipping data.

Development of gas pipeline to Asia

As seen in Figure 20, most current natural gas pipelines in Asia stretch only a few hundred

kilometers from production areas to consumption areas and have a capacity of a mere 5 to 15 bcm/year.

However, from the results of the model based infrastructure maps in Figure 21, both natural gas

pipeline volume and network distance are expected to experience great growth in both international

51

and domestic pipeline networks. In this subsection, the evaluation of the scale of pipeline networks is

carried out for all of Asia.

As the model calculation gives the transported volume by route, an original conversion method

for the total sum of the product of pipeline distance and throughput of each pipeline is adopted for all

the pipelines whose destination or source is in Asia. Introducing this evaluation will make it possible to

express network size quantitatively.

Figure 23 shows the development of the total sum of the product of pipelines and throughput

on the left axis and converted pipeline distance on the right axis with throughput of 20 bcm/year, which

is equivalent to a high-pressure trunk pipeline approximately 1 m (40 inches) in diameter. As a result of

this expression, around 40,000 km of 20 bcm/year pipeline until 2020 or 230,000km until 2050 will be

constructed within Asia.

For instance, the West to East pipeline is said to be a project with a distance of 4,000 km and

capacity of 15 bcm/year, so the project is equivalent to one with a distance of 3,000 km and capacity of

20 bcm/year. The Trans-ASEAN Gas Pipeline project is approximately 4,000 km with 20-40 inch

pipelines.

Also, as shown in the Box 5, the magnitude of pipeline network will become comparable to

current European international transmission lines at around 2020, and also become comparable with

the major trunk lines in the United States at around 2050.

0.E+00

1.E+06

2.E+06

3.E+06

4.E+06

5.E+06

2000 2010 2020 2030 2040 2050

km b

cm/y

r

0

50

100

150

200

250

1,000km@

20bcm

/yr

Figure 23: Development of transmission pipeline magnitude in Asia.

Right axis is normalized by throughput capacity of 20bcm/year.

52

Observation - Natural gas pipelines in Asia

• Magnitude of pipeline grids in Asia will become equivalent to European pipeline

network by 2020, or to the US trunk lines by 2050.

Box 5 Total pipeline distance

Pipeline distance and pipeline capacity are often used to express pipeline magnitude. Here, in this

model analysis, an index is introduced to express the magnitude, which is the converted distance with

20 bcm/year of transportation capacity. As seen on the report, a 4,000 km pipeline with a throughput of

15 bcm/year is equivalent to a 3,000 km pipeline with a throughput of 20 bcm/km.

In this expression, the magnitude of current major European long distance international pipelines is

equivalent to about 39,600 km (actual transportation distance is 25,700 km) and the magnitude of

major US domestic trunk lines is 230,700 km (actual transportation distance is 120,000 km).

So, it may take 50 years for the pipeline network in Asia to grow to a capacity comparable to that in the

United States.

Role of suppliers ~ Natural gas trade to Northeast Asia and South Asia

As seen up until now, from the perspective of demand, natural gas imports in Northeast Asia

and South Asia should increase greatly. In this subsection, the changes in the roles of suppliers in

these regions are examined.

Table 14 and Table 15 show model results for natural gas transportation to Northeast Asia and

South Asia, respectively, sorted by natural gas suppliers. In each cell, the upper figures indicate the

annual natural gas flow and lower figures in parentheses indicate the volume carried by LNG out of the

total volume.

To Northeast Asia (bcm/yr) Total supply (LNG supply)

From 2000 2010 2020 2030 2040 2050 SE Asia 65.4

(65.4) 78.4

(67.4) 69.5

(51.6) 51.8

(33.2) 40.0

(20.5) 36.9

(17.2) Oceania 9.9

(9.9) 14.3

(14.3) 48.7

(48.7) 46.0

(46.0) 42.8

(42.8) 38.8

(38.8) M. E. 21.1

(21.1) 15.4

(15.4) 29.8

(29.8) 77.6

(77.6) 130.8

(130.8) 206.5

(206.5) FSU 0.0

(0.0) 59.6 (5.6)

103.0 (7.2)

150.4 (10.2)

377.7 (10.2)

673.3 (10.2)

Other 1.7 (1.7)

0.8 (0.8)

0.4 (0.4)

0.0 (0.0)

0.0 (0.0)

0.0 (0.0)

Table 14: Natural gas imports to Northeast Asia by supply region.

53

To South Asia (bcm/yr) Total supply (LNG supply)

From 2000 2010 2020 2030 2040 2050 M. E. 0.0

(0.0) 47.6

(14.0) 131.9 (18.5)

331.8 (45.9)

574.9 (145.4)

880.4 (243.2)

FSU 0.0 (0.0)

0.0 (0.0)

0.0 (0.0)

0.0 (0.0)

54.2 (0.0)

54.2 (0.0)

Table 15: Natural gas imports to South Asia by supply region.

Images in Figure 24, which are created from Table 14 and Table 15, show illustrated views on

the changes in the roles of suppliers to each destination over time.

From To Northeast Asia To South Asia

SEAsia

Oceania

M. E.

FSU

Figure 24: Change in roles by supply region (illustration).

Illustrated from Table 14 and Table 15

Year

Volum

e

54

Regarding suppliers to Northeast Asia, the role of Southeast Asia and Oceania, which are

existing suppliers, are almost same or changed only slightly, but the role of Russia via pipelines and the

Middle East via LNG will increase dramatically after 2020.

As for South Asia, as can be seen in the infrastructure maps in Figure 21, the role of the Middle

East will increase. In other words, the rapid dependence on natural gas in this region is supported by

the Middle East. FSU (Central Asia) will also start supplying this region around 2040, together with the

Middle East.

Observation - Natural gas supply to Northeast and South Asia

Northeast Asia

• Southeast Asia and Oceania, will retain their roles as suppliers

• Russia (pipelines) and the Middle East (LNG) will gain greater roles

Southeast Asia

• Pipeline gas from Middle East is the primary role supported by LNG also from the

Middle East

• Supply from Central Asia will also start in 2040

4.2 Role of natural gas

In the previous section, natural gas transportation was examined qualitatively and

quantitatively. In this section, the role of natural gas and the amount of natural gas are analyzed by

examining the primary energy supply, natural gas consumption, generated power by sector, and CO2

constraints.

Primary energy supply and share of natural gas in Asia

In 2000, annual natural gas consumption in Asia is merely 263 MTOE/year (or 274 bcm/year),

and this means only a 9.1% share of the total primary energy supply in Asia, which is 2888 MTOE/year.

In this subsection, an analysis of the share of natural gas in the primary energy supply over 50 years is

carried out. From the results, we would like to determine the change in the role played by natural gas in

primary energy.

Figure 25 shows the results of model calculation for the primary energy supply in Asia (on left

axis, MTOE/year) and the share of natural gas in the PES (on right axis, %). This graph includes

renewables -- fuel wood, biomass to secondary energy, solar power, wind power, and geothermal

power.

55

In Asia, the increase in coal and oil consumption is gradual, but, at the same time, natural gas

usage grows dramatically. As already described, the total amount of natural gas use in 2000 is about

263 MTOE/year, but, in 2050, it will exceed or become equivalent to coal and oil supply, reaching 2199

MTOE/year in 2050, which is eight times more for than in 2000, 38% of the primary energy supply. This

is explained by the fact that natural gas is used not only for gaseous demand but also for electricity

demand.

0

1000

2000

3000

4000

5000

6000

2000 2010 2020 2030 2040 2050

Prim

ary

Ene

rgy

Sup

ply

(MTO

E/yr

)

0

10

20

30

40

Share of N

atura

l Ga

s (%)

Natural Gas Crude Oil CoalRenewables Nuclear Gas (%)

Figure 25: Primary energy supply and share of Natural gas.

Observation – Natural gas as a primary energy

• Initially, natural gas use is quite limited in Asia, but consumption will increase by 8 fold

over 50 years

• Natural gas share will grow from 10% to 38% in primary energy supply.

Natural gas balance in Asia

The current natural gas supply in Asia is mainly dependent on regionally produced natural gas

and LNG import to Japan, Korea and Chinese Taipei. As a result, natural gas flow between Asia and

other regions is not seen except for LNG. In 2000, 43% of natural gas is consumed for power

generation, with the rest being used for gaseous demand including industrial, residential and

transportation use. (Table 16)

56

Supply (bcm/year) Demand (bcm/year) Production Import Others

249.7 22.1 -0.9

Electricity Gaseous Demand

- Industry - Residential - Other Sectors

115.1 155.7

68.7 30.5 56.4

Total 270.8 (bcm/year)

Table 16: Current natural gas use in Asia. Source: Assembled from Energy Balances of OECD Countries, and

Energy statistics of Non-OECD Countries.

In this subsection, the balance of natural gas supply and demand (production and imports, and

natural gas usage) in Asia is examined from model results over time, and an attempt is made to

analyze the role of natural gas.

Figure 26 shows the natural gas balance in Asia in the Base Case, positive bars indicate

supply from regional production and imports from outside the region. Negative bars indicate

consumption for gaseous and electricity demand. In the figure, LNG and pipeline imports are shown,

indicating the flow from outside the region but not the flow within the region.

As often mentioned, the natural gas consumption in Asia will increase by eight fold to 2286

bcm/year in 2050 from its current level of 274 bcm/year (263 MTOE/year). Regional natural gas

production increases, but soon levels out in 2020, and, in order to meet the steeply growing demand,

LNG and pipeline imports increase greatly. In particular, the pipeline supply from outside the region

grows dramatically, with pipeline gas eventually supplying three fourths of natural gas imports.

One half to two thirds of supplied natural gas is used to satisfy gaseous demand.

-3000

-2000

-1000

0

1000

2000

3000

2000 2010 2020 2030 2040 2050

bc

m/y

ea

r

Import(LNG)Import(PL)

ProductionPower Gen.

Gas Demand

Figure 26: Natural gas balance in Asia from 2000 to 2050 (bcm/year).

57

Figure 27 shows graphs of natural gas balance by sub-regions. As shown in graph a),

Northeast Asia must rely on imported natural gas because of the limited natural gas resource in this

region. Natural gas in this region is initially used mainly for gaseous demand but shifts to electricity

demand.

Although, both, Southeast Asia and Oceania, are rich in natural gas resources, the uses of the

gas are different with each other. In Southeast Asia, as the demand within the region increases, the

amount of export decreases. On the one hand, Oceania is represented by developed countries like

Australia and New Zealand, and its demand style has not change drastically. As a result, Oceania

keeps its position as an exporter.

As South Asia is located next to the Middle East, which has huge resources of natural gas, and

Central Asia, which also has natural gas resources but does not have an explicit market, the growth of

natural gas is extraordinary due to the import.

a) Northeast Asia

-1500

-1000

-500

0

500

1000

1500

2000 2010 2020 2030 2040 2050bc

m/y

r

b) Southeast Asia

-400-300-200-100

0100200300400

2000 2010 2020 2030 2040 2050bc

m/y

r

c) Oceania

-150

-100

-50

0

50

100

150

2000 2010 2020 2030 2040 2050bc

m/y

r

d) South Asia

-1500

-1000

-500

0

500

1000

1500

2000 2010 2020 2030 2040 2050bc

m/y

r

Figure 27: Natural gas balance by sub-regions.

58

As a result, increases in the volume of natural gas in Asia are supported by demand from

Northeast Asia and South Asia.

Observation – Natural gas balance in Asia

• Natural gas consumption increases 8 fold by 2050.

• Natural gas production in Asia levels out.

• Eventually, 3/4 of natural gas comes from outside Asia.

• 3/4 of imports come through pipeline.

• 1/2 ~ 2/3 of supplied natural gas is consumed for gaseous demand.

• Natural gas consumption increases drastically in Northeast and South Asia.

• Southeast Asia and Oceania remain as exporters of natural gas but the amount

remain almost as the same.

Electricity in Asia

This model assumes four types of final energy demand -- solid, liquid, gaseous, and electricity

demand. For this model setting, natural gas will be consumed for all gaseous demand and part of

electricity demand. On the other hand, regarding power generation, in addition to natural gas, other

forms of fossil energy, such as coal and oil, and nuclear, hydro, geothermal, and solar power -- are

alternative sources for electricity.

This means that the change in natural gas's share of electric power generation indicates a cost

advantage to other fuels. Particularly with the Base Case, as additional considerations are introduced

to handle global climate changes, this analysis will explain the price advantages of natural gas and

environmental options

Figure 28 indicates the supply of power generation in Asia by sector (TWh/year, left axis) and

the share of natural gas in power supply (%, right axis). According to the figure, the main supplier of

electricity in Asia will shift from coal, currently the dominant source, to a combination of coal and natural

gas. The amount of coal use will not increase much, so natural gas power generation will satisfy most

of the increase in power demand in Asia. Particularly in the latter part of the target period, when

environmental limitations become stricter, use of natural gas will increase.

As with coal power generation, renewable power generation, including biomass, and nuclear

generation maintain most of their current amount of the power supply. Natural gas's share of the power

sector will increase from its current level of 16% to 50% in 2050.

59

0

2000

4000

6000

8000

10000

12000

14000

16000

2000 2010 2020 2030 2040 2050

Elec

. Sup

ply

(TW

h/yr

)

0

10

20

30

40

50

60N

atura

l Ga

s Share (%

)

Natural Gas Fueled Oil Fired Coal FiredNuclear Renewables Gas Share

Figure 28: Electricity generation and share of natural gas by fuel source in Asia

Observation - Power generation in Asia

• Share of natural gas power generation will grow from 16% (@2000) to 50% (@2050)

of total power generation system in Asia

• In particular, additional power generation is provided by natural gas based generation

CO 2 emission reduction program in Asia

As explained in the previous subsection, use of natural gas power generation to cover

additional power demand is a realistic option to satisfy the Base Case scenario. The next issue is to

determine how the world can be changed so that no CO2 limitations are taken. Additional issue is to

determine what will happen to the role of natural gas when no anti-climate action is taken.

In this final subsection, an alternative scenario called the Reference Case, is considered where

all the settings are the same as the Base Case, with the single exception being that there are no

limitations on CO2 emissions. The role of natural gas in CO2 reduction is described by comparing the

Base Case and the Reference Case

Figure 29 compares fossil fuel consumption in Asia in the Reference Case and the Base Case.

As shown in the figures, reducing the use of coal (by 50% compared to the Reference Case) from the

60

primary energy supply is optimal from the standpoint of cost analysis. On the other hand, it should be

noted that natural gas (and oil) consumption does not change much in the two scenarios.

a) Reference Case

0

500

1000

1500

2000

2500

3000

2000 2010 2020 2030 2040 2050

PES(

MTO

E/yr

)

Natural GasCrude Oil

Coal

b) Base Case

0

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1000

1500

2000

2500

3000

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Crude OilCoal

Figure 29: Primary energy supply (MTOE/year) in Asia.

Figure 30 compares the two cases’ final energy consumptions in Asia sorted by demand type.

The graph reveals that energy savings for all energy demand types is achieved, although the amount

differs according to energy type, with electricity and liquid demands seeing savings of 8 to 11%, and

gas and solid demand types seeing savings about 25%

a) Reference Case

0

500

1000

1500

2000

2500

2000 2010 2020 2030 2040 2050

FED

(MTO

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Gas LiqSol Ele

b) Base Case

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2500

2000 2010 2020 2030 2040 2050

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(MTO

E/yr

)

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Sol Ele

Figure 30: Final energy demand (MTOE/year) in Asia.

Figure 31 compares annual power generation sorted by power source. By 2030, virtually the

same amount of power is generated by natural gas in the two cases, and after that the amount in the

Base Case surpasses that in the Reference Case. On the other hand, coal based generated power

shows a significant difference after 2030.

According to this, adding natural gas power generation is an effective solution for power supply,

with or without CO2 emission limitations, but, if CO2 emission limitations are introduced, they will

increase the natural gas power supply.

61

a) Reference Case

0

5000

10000

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b) Base Case

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er G

en. (

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Figure 31: Electricity generation (TWh/year) in Asia.

Finally, Figure 32 shows a CO2 emission reduction option in Asia. In this figure the upper line

indicates the CO2 emission from the Reference Case. This figure shows that virtually the same amount

of energy savings (conservation) and fuel switching between fossil fuels reduces the Reference Case's

emission volume to the level of the black area, which indicates net emissions in the Base Case, and net

emissions succeed in staying below the global CO2 concentration level of 550ppmV.

0.0

2.0

4.0

6.0

8.0

2000 2010 2020 2030 2040 2050

CO

2 Em

issio

n (G

t-C

/yr)

Conservation

Fuel Switch

Net Emission

Figure 32: CO2 emission in Asia from “Reference Case” and “Base Case”.

Emission from Reference Case

Emission from Base Case

62

Observation - CO2 emission control

• Energy supply: 50% reduction of coal use in Reference Case

• Demand side: 8-25 % energy savings

• As natural gas power generation increases in the Reference and Base Cases,

supplying additional electricity with natural gas becomes an effective policy

• CO2 emission reduction options come from energy conservation and fuel switch and

they are equally effective

63

5. CONCLUSIONS

In this report, in order to investigate the potential of natural gas for resolving global climate

change issues, a detailed energy infrastructure model for Asia is developed, and a set of model

calculation results are analyzed based on the Base Case. From this model-based analysis, a

development view of natural gas infrastructure in Asia over a 50-year period and the role of natural gas

are obtained under the constraint that global CO2 concentration is less than 550 ppmV during the 21st

century.

Expanding natural gas infrastructure in Asia

Expanding natural gas use based on the development of natural gas infrastructure will enable

Asia to resolve global warming issues with a natural gas based solution. The following are key points

from the model regarding the natural gas transportation system.

• Natural gas pipelines in Asia, which currently play a very limited role, will expand,

starting with the linking of production areas with neighboring consumption areas, and

finally expanding throughout the Asian region, together with LNG supply to coastal

regions.

• With the expansion of international pipelines and LNG in 2050, 1/4 of natural gas

demand will be produced within the region, and 3/4 of the remainder (that is

approximately 60% of total natural gas consumption) will be carried by pipeline.

• During the next 20 years, pipeline construction will extend 40,000 km and be

normalized with 20 bcm/year. After 50 years, it will extend 230,000 km, which is

equivalent to 6 times the circumference of the earth.

• LNG trade to Northeast Asia will increase rapidly in the first half of the target period,

and, in the latter half, LNG trade to South Asia will increase.

Great increase in natural gas use

An increase in natural gas use will occur due to demand for power generation as well as

gaseous demand. With increased usage, natural gas will have the chance to become one of the most

important energy sources in Asia. From the standpoint of regional dependency, natural gas usage in

South Asia, which is located near the resource rich Middle East, accounts for a large proportion of its

primary energy supply. South Asia and Northeast Asia will consume larger volumes of natural gas.

Here are observations regarding natural gas use.

• Natural gas consumption will increase from 263 MTOE/year as of 2000 to 2199

MTOE/year in 2050, an 8 fold increase.

• From one half to two thirds of the natural gas supply is used to satisfy gaseous

64

demand, with the rest used for power generation.

• Natural gas will supply 50% of electrical power generation in 2050.

Role of natural gas in reducing CO 2

In the world like Base Case where the world try to achieve the world CO2 concentration target,

CO2 reduction will be carried out through energy saving from all kind of energy demands and fossil fuel

switches. The following key points were ascertained through a comparison of the Base Case with the

Reference Case, which has no CO2 limitations.

• All types of demand see an 8-25% reduction compared to the Reference Case.

• Regarding supply, coal use is reduced by 50% compared to the Reference Case, and

natural gas and oil use is not affected in either scenario.

• Therefore, energy savings and a fuel switch are important solutions for meeting CO2

limitations.

• Increasing natural gas based electricity is an effective policy because power

generated by natural gas remains almost the same in both scenarios, despite a

general reduction in demand for electricity.

65

REFERENCES

[1] USGS World Energy Assessment Team (October 2000). “DDS-60: U.S. Geological Survey

World Petroleum Assessment 2000-Description and Results”,

http://greenwood.cr.usgs.gov/energy/WorldEnergy/DDS-60/

[2] IGU WGC2003 – Thorn, T. H. (Chairman of WOC9), (will be available in June 2003). “WOC9

report” for the World Gas Conference 2003, Tokyo.

[3] Rogner, H-H. (1997). “An Assessment of World Hydrocarbon Resources”, Annual Review

Energy Environment 1997,22:pp. 217-262

[4] BP (June 2002). “BP Statistical review of world energy 2002”, http://www.bp.com/

[5] WEC (1998). “Survey of Energy Resources 1998”, http://www. worldenergy.org/wec-geis/

[6] NASA, SeaWIFs. http://www.giss.nasa.gov/data/seawifs/data/

[7] National Climate Data Center (NCDC) – NOAA. Global Surface Summary of Day,

http://www.ncdc.noaa.gov/oa/ncdc.html

[8] CEReS (Center for Environmental Remote Sensing, Chiba University) - Chiba Univ., AARS

Global 4-minute Land Cover Data Set, http://ceres.cr.chiba-u.ac.jp:8080/usr-dir/you/ICHP/index.html

[9] Statoil. Slipner gas field, http://www.statoil.com/

[10] IEA (2002). “Energy Balances of OECD Countries,1999-2000: 2002 Edition” & “Energy

Balances of Non-OECD Countries: 2002 Edition”.

[11] IPCC – Nakicenovic, N. and Swart, R. (Eds.), (2000). “Emissions Scenarios”, Cambridge

University Press.

[12] IGU WGC2003 – Yamaji, K. (Editor), (will be available in June 2003). “Special Project 1 -

Global Energy Scenarios” for the World Gas Conference 2003, Tokyo.

[13] IGU WGC2000 – Clark, R. S. (Chairman of WOC6), (June 2000). “WOC6.3 report” for the

World Gas Conference 2000, Nice.

66

22nd World Gas Conference June 1-5, 2003, Tokyo, Japan

Report on Special Project 1-A

Appendices

Appendix A

Reviews of the natural gas market in Asia

Appendix B

Storylines on Asia’s natural gas perspectives

67

Report on Special Project 1-A Appendix - A

Reviews of the

natural gas market

in Asia

Lead Author

Preety Bhandari

The Energy and Resources Institute

& Asian Energy Institute

68

Reviews of the natural gas market in Asia

Lead Author

Preety Bhandari, The Energy and Resources Institute

Joint work with

Asian Energy Institute

69

1. Introduction The link between energy and economic growth has been empirically observed throughout the

world, and is well recognized; energy is accepted as an important driver of economic growth. This is

even truer for developing countries that have, unlike developed countries, been unable to decouple the

two.

Common to the developed and the developing countries is a gradual shift in preference

towards natural gas, the discovery of which, until a few decades back, would have been a

disappointment for the explorer. Both construction and transportation economics have shifted in favour

of natural gas. Growing environmental concerns involving the use of coal, security concerns involving

the consumption of crude oil, and improvements in combined cycle technology have also supported

this shift. The Asia-Pacific region has not remained untouched by this process and, in fact, has taken

the lead in the trade of natural gas. Japan and South Korea are now the world’s largest importers of

natural gas, and Malaysia and Indonesia are two of its largest exporters. Though trade in natural

gas still forms a tiny portion of its consumption, it is slated to increase manifold.

This paper reviews the natural gas market in the Asia-Pacific region today, analyses the

opportunities for cross-border trade, and projects the future demand and supply scenario for the fuel. It

starts with an overview of past trends in energy consumption in the Asia-Pacific region and moves on to

analyse the trend in natural gas consumption. After studying the demand–supply gap in the region, it

looks at trade flows in this market and the associated changes in the market set-up.

2. Trend in energy consumption in the Asia-Pacific region Over the past three decades, commercial energy consumption in the Asia-Pacific region has

grown by 4.1% per annum—2.1 percentage points higher than the world growth rate. Over this period,

only the Middle East and Africa have shown a higher energy consumption growth rate of 5.8% and

4.5%, respectively. As a result of its high growth rate, the Asia-Pacific region’s share in the total world

commercial energy consumption has risen to 27.5% in 2001 from 14.8% in 1970 and from 22.5% a

decade ago. Although the Asian financial crisis of 1997 affected the region’s energy consumption,

growth over the period 1996–2001 was 0.8%, the region accounted for 69% of the total increment in the

1990s. With the FSU (former Soviet Union) in decline and North America and Europe fluctuating

between growth and decline, it is the Asia-Pacific region that has been at the forefront and has played

an important role, which is illustrated in Figure 1.

Within the Asia-Pacific region, South Korea, Malaysia, Indonesia, and Thailand have seen the

highest growth rates in energy consumption for the past three decades with growth rates touching 11%

in 1970s. It is only during the last five years that these countries have witnessed a slowdown. China

has been the main driver of absolute increase, as it accounts for 33% of the region’s energy

consumption. Japan accounted for a large share of the increase till the beginning of the 1990s, but its

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prolonged economic slowdown has reduced its weight. India has achieved steady but low growth and

now accounts for 12.8% of the region’s energy consumption. The share of major countries in

incremental energy demand in the Asia-Pacific region is shown in Figure 2.

Figure 1 Annual incremental energy demand by regions

Source: BP (2002)

Figure 2 Annual incremental energy consumption in Asia-Pacific by countries

Source: BP (2002)

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Figure 3 shows the share of various fuels in total energy consumption in the Asia-Pacific

region.

Figure 3 Trends in fuel-wise primary energy consumption in Asia-Pacific

Source: BP (2002)

Though the share of natural gas is lower than that of coal and crude oil in the region, it has

been one of the fastest growing fuels, as detailed below.

Most of the data in this section is from the BP Statistical Review of World Energy 2002, unless otherwise quoted.

3. Role of natural gas The shift towards natural gas from crude oil and coal is taking place universally. Its share in

world energy consumption rose from 18% in 1970 to 24% in 2001. However, there are significant

inter-regional differences. Traditionally, it has been the developed countries that have seen large

increases in natural gas consumption since the twin oil price shocks of the 1970s. The trends in various

regions are shown in Figure 4.

As Figure 4 illustrates, North America managed to reduce its consumption of natural gas in the

1970s, a possible reason for which are the severe efficiency standards that were imposed after the twin

oil price shocks. However, dampened interest in energy security due to a prolonged period of low

energy prices and stable energy markets caused consumption to rise again from the mid-1980s.

Consumption in the FSU rose dramatically over the period 1970–1992 and slowed down in the 1990s

after the country broke up. It has, however, started to pick up in recent years. All other regions have

seen a more or less steady rise over the period 1970–2000. However, of the total increase of 993

MTOE (million tonnes of oil equivalent) worldwide during the 1990s, the Asia-Pacific region accounted

72

for 685 MTOE (69%), which proves its importance in the natural gas market.

Figure 5 shows the share of various regions in incremental natural gas consumption during the

last decade.

Figure 4 Trends in natural gas consumption of various regions

Source: BP (2002)

Figure 5 Annual incremental natural gas consumption by regions (1990–2001)

Source: BP (2002)

The Asia-Pacific region’s share in energy consumption grew at more or less the same pace as

its share in natural gas consumption till the financial crisis in 1997 (Figure 6). Since 1997, while the

share in energy consumption has not risen, that in natural gas has increased. This indicates the

growing importance of natural gas in the region. This can be attributed to the fact that most of the

73

natural gas consumed is in the transformation sector, specifically the power sector, while crude oil is

consumed in the final consumption sector, which was affected by the economic slowdown. Coal – a

major input for industry – also declined due to a fall in industrial activity. And, though its absolute share

is low, the region has seen one of the highest natural gas consumption growth rates over several

periods, as shown in Table 1.

Figure 6 Share of Asia-Pacific in total energy and natural gas consumption

Source: BP (2002)

Region/Period 1970–2000 1990–2000 1996–2001 North America 0.2 1.9 -0.4 South and Central America 5.7 4.8 4.2 Europe 4.8 3.3 2.1 Former Soviet Union 3.7 -1.9 -0.2 Middle East 8.8 7.0 6.0 Africa 12.7 5.1 5.0 Asia-Pacific 10.4 (2) 6.3 (2) 5.3 (2) World 2.9 2.0 1.6

Table 1 Natural gas consumption growth rates

Note: Figures in bracket indicate rank among all the regions

Source: BP (2002)

Key natural gas consumers in the Asia-Pacific region are Australia, China, India, Indonesia,

Japan, Malaysia, South Korea, and Thailand, accounting for about 85% of total consumption (Figure 7).

In absolute terms, Japan is the largest consumer, followed by South Korea. Japan accounted

for 19% of the total increment in demand over the period 1990–2001, South Korea for 13%, and

Thailand for 11%. Till recently, India was the third largest gas consumer in the region, but supply-side

constraints yielded that position to China last year. However, India accounted for 9.4% of the total

incremental demand over the last decade.

Chinese Taipei and South Korea have witnessed the highest annual growth rate of 13.4% and

19.2%, respectively, followed by Thailand with 13%, over the period 1990–2001. Consumption in

Indonesia, Malaysia, and Australia has increased 1.5 times over the last 10 years, but their production

74

has increased at a faster pace, enabling them to remain net exporters of natural gas. Consumption in

India has grown at 5.1% per year for the last five years, but the latent demand for natural gas, which

can be as high as 136 MCMD (million cubic metres per day) by 2006/07 by some estimates, could

easily make India one of the biggest gas consumers in the region. Figure 8 shows the share of various

countries in incremental natural gas consumption.

Figure 7: Natural gas consumption trends in major Asian countries

Source: BP (2002)

Figure 8: Annual incremental natural gas consumption in Asia-Pacific by countries

Source: BP (2002)

75

Reasons for this growth in natural gas consumption abound. First, costs associated with

transportation have declined dramatically in the last decade. High costs limited consumption to a few

favourably located power and petrochemical plants. Most of the associated natural gas was flared and

free natural gas wells were capped. For example, prior to the commissioning of the HBJ

(Hazira–Bijaipur–Jagdishpur) pipeline system in India, the state-run ONGC (Oil and Natural Gas

Corporation) used to flare the natural gas produced in the western offshore fields.

Second, advances in CCGT (combined cycle generation technology) with concomitant

deregulation in the electricity markets made natural gas the favourite fuel. Development of CCGT let

natural gas turbines be used economically for peak-load operations since the price for electricity

supplied during peak hours went up due to deregulation and adoption of time-of-use pricing. Other

reasons like lower gestation lags, higher efficiency, benign environmental impact, and low start-up time

of such turbines also contributed to their popularity.

Third, security concerns, generally associated with crude oil, are absent in the case of natural

gas. It is true that three-fourths of the proven natural gas reserves in the world are concentrated in 10

countries, of which 5 are in the Middle East. This structure is very similar to that in crude oil reserves,

where seven countries hold three-fourths of the total proven crude oil reserves, and five out of them are

Middle East countries. This concentration of oil reserves in few countries has led to the formation of a

cartel called OPEC (Organizations of Petroleum Exporting Countries). OPEC has successfully

influenced prices of crude oil over the past few years. However, the possibility of the formation of a

cartel controlling natural gas reserves is remote. The main difference in the reserves set-ups of crude

oil and natural gas is the dominance of Russia in the latter, accounting for 36% of the total gas reserves

worldwide and is outside of any cartel. Moreover, while 77% of total natural gas consumption takes

place in the country where it is found, the corresponding percentage for crude oil is 52%, because

transporting natural gas is difficult compared to transporting crude oil. Moving natural gas from the

producer’s location to the consumer’s location involves massive investments in the entire chain,

whether it is transported via a pipeline or via the sea. This means that the natural gas industry is

characterized by long-term contracts between various stakeholders, which reduce the possibility of

manipulation though they lower market liquidity. However, geo-political imperatives can pose a major

threat to proposed natural gas pipeline projects and undermine the overall security of the fuel.

4. Natural gas reserves The total global proven reserves of natural gas stood at 155 TCM (trillion cubic metres) at the

end of 2001, having grown at 1.73% annually over the last decade. The EE (Eastern Europe) along

with the FSU, and the Middle East account for 30% and 35% of world natural gas reserves, respectively.

However, while the reserve accretion in the EE and the FSU has been almost nil in the past decade, the

Middle East has shown continuous growth of 3.78% (Figure 9).

76

Figure 9: Region-wise trends in proven reserves

Source: BP (2002)

According to an assessment of the USGS (United States Geological Survey), there is still 143

TCM of natural gas to be discovered by 2025. Of this, the FSU accounts for 31%, and the Middle East

for 20%. In the FSU, much of the reserves are believed to lie in the Caspian Sea and in eastern Russia.

Figure 10 compares proven and mean undiscovered reserves, by region.

The FSU and the Middle East together account for 50.8% of the total undiscovered natural gas,

and hence, are expected to retain their dominance in natural gas reserves. The Asia-Pacific region’s

undiscovered reserves are more than double its proven reserves but are less than those in the Middle

East and the FSU.

Figure 10: Region-wise comparison of natural gas reserves

Note Numbers represent undiscovered reserves as a percentage of proven reserves at the end of 2001.

Source: USGS (2000); BP (2002)

77

The Asia-Pacific region accounts for 8% (third highest) of the world’s proven natural gas

reserves and for about 9.6% of its undiscovered reserves. Australia, Indonesia, and Malaysia account

for 59% of proven reserves. While Indonesia and Malaysia together accounted for 52% of the total

reserve accretion over the decade 1980–1990, Australia accounted for 56% over 1990–2000. Reserve

accretion for Bangladesh, India, and Thailand was negative in the last decade. This suggests a

negative reserve replacement ratio. Figure 11 compares proven and undiscovered reserves for

countries in the region.

Australia and Indonesia have the largest undiscovered reserves. China has the potential to

discover 178% of proven reserves, but the country is not likely to become an exporter.

Figure 11: Country-wise comparison of natural gas reserves

Note Numbers represent undiscovered reserves as a percentage of proven reserves at the end of 2001.

Source: USGS (2000), BP (2002)

Figures for natural gas reserves are derived from BP (2002). It is, however, realized that these figures are constantly revised

and hence may not conform to all estimates. This is especially true for FSU.

5. Natural gas trade Europe produces only 12% of the world’s natural gas, but accounts for 19.5% of consumption.

The FSU, Middle East, and Africa together account for 41% of production but consume only 33.7%.

South and Central America, North America, and the Asia-Pacific region have demand–supply

equilibrium but this is due to significant intra-regional trade. Thus, trade plays an important role in

balancing supply and demand. Figure 12 shows regional import and export dependency on natural gas.

Import dependency is highest for Europe and export dependency is highest for Africa. Since

significant intra-regional trading takes place in the Asia-Pacific region, both ratios have been shown for

the region. Figure 13 shows the deficit/surplus in natural gas for countries in the Asia-Pacific region.

78

Only Japan and South Korea presently import natural gas in any significant quantity. Chinese

Taipei, Thailand, and New Zealand also import some. China and India are expected to be major

importers in the near future. In China and India, many gas infrastructure projects have been planned

that are likely to reduce supply-side constraints in both countries (Annexe 1)

Figure 12: Imports/exports as a percentage of consumption/production

Source: BP (2002)

This figure shows only the prominent percentage. Although several regions are both importers and exporters, both ratios are

depicted only for Asia-Pacific, keeping in mind the objectives of the study.

Figure 13: Natural gas deficit/surplus in Asia-Pacific

Source: BP (2002)

79

Japan accounts for 70% of Asian natural gas imports and South Korea for 21% (Table 2). While

Chinese Taipei, Singapore, and Thailand import natural gas from Asia-Pacific countries only, Japan and

South Korea import 24% and 56%, respectively, from outside the region. The Middle East is the most

important source outside the region, accounting for 22% and 56% of imports by Japan and South

Korea, respectively.

Country Within AP Outside AP From ME Total Japan 56.26 17.81 16.02 74.07 South Korea 9.69 12.14 12.14 21.83 Chinese Taipei 6.30 0 0 6.30 Singapore 2.50 0 0 2.50 Thailand 1.75 0 0 1.75 Total 76.50 29.95 28.16 106.45

Table 2 Natural gas flows in Asia-Pacific (billion cubic metres)

Note: AP – Asia-Pacific; ME – Middle East

Source: BP (2002)

Because of the differences in market characteristics as pointed out in Box 1, and because

there is almost no inter-regional trade, there is no true global natural gas market. North America,

Europe, and Asia-Pacific are all separate markets with different peculiarities and problems.

Box 1 gives a broad outline of the natural gas market in the world and specifically in the

Asia-Pacific region. In order to identify possible future flows, we examine the projections of natural gas

demand and supply for the region for the next three decades.

Box 1 Natural gas markets

Natural gas is transported by two principal modes: (1) pipeline, that may be overland

or offshore, or (2) tankers after liquefaction. Both have advantages and disadvantages, and

cater to different market segments.

Pipelines are the ideal mode for transporting gas within a country, especially if they

are overland. However, they can become cost-prohibitive if the distance is large. The cost of

laying an offshore pipeline is enormous and, hence, only a few of them exist. If natural gas

flow is cross-border, then laying the pipeline involves various geo-political issues like right of

way, political stability of countries involved, right of transit (if transaction is multilateral), and

harmonization of rules and regulations. Nonetheless, pipelines are used for cross-border

trade. More than 90% of USA’s natural gas imports are through pipelines. Cross-border

pipeline trade is also common in Europe. Russia, Norway, and the Netherlands are the major

exporters, and Germany, Italy, and France the major importers.

80

Moving gas in the form of LNG (liquefied natural gas) supersedes the issues involved

in cross-border pipeline transfer. Since investments required in an LNG train are of very large

order, LNG is the ideal mode for transporting natural gas over a larger distance, and is

economical if the countries involved do not share a common overland border.

Apart from these factors, there are certain structural differences between markets

served by pipelines and LNG. In a majority of the western markets, pipeline flows are normally

base-load flows that cater to base-load consumption by the country. On the other hand, LNG

serves to fill the gap between pipeline flows and domestic supply and the expected demand

with some percentage adding to base load as well. Thus, the US saw an increase in the

number of LNG shipments in the year 2000 when natural gas demand rose over historical

levels and prices rose to 10 dollars per million metric British thermal unit. Having said that, it is

also true that the current global spot market in LNG is marginal. Reduction in construction

costs of both receiving and re-gasification terminals and of ships will help promote spot trade

in LNG.

Natural gas trade in the Asia-Pacific region is, however, different from that in the

West. Ninety per cent of the trade in the form of LNG, with a few pipelines, flows between

Singapore and Indonesia, Singapore and Malaysia, and Thailand and Myanmar. The choice of

LNG for natural gas transportation in Asia-Pacific is a geographical imperative since the major

gas-consuming countries – Japan and South Korea – are situated far from the supply centres.

Due to this predominance of LNG in the Asia-Pacific natural gas flows, LNG no longer serves

a swing role but is used for base-load consumption. This further implies that the spot market

has not developed in the region because long-term contracts are predominant.

Another important difference between Western markets and the Asia-Pacific market is

that unlike in the Asia-Pacific, natural gas has been commoditized in the West. There are

well-developed spot and futures markets in the West that allow free market pricing and

provide liquidity to the market, thereby enhancing the security of supplies. Existence of natural

gas supply infrastructure, which can quickly and efficiently move natural gas from one location

to another so that arbitrage opportunities may be exploited, prevents manipulation. On the

other hand, natural gas in the Asia-Pacific region is traded under long-term contracts that

deprive the market of liquidity and involve lengthy and costly negotiations.

Lastly, there is a difference in pricing mechanisms adopted in the three regional

markets. While in North America, imported natural gas is priced with reference to the domestic

gas prices established at the Henry Hub, in Europe and Asia-Pacific, it is priced with reference

to the prices of alternative fuels, which is fuel oil in Europe and crude oil in the Asia-Pacific

region.

81

6. Natural gas demand projections

The WEO (World Energy Outlook) 2002 projects natural gas demand at 4203 MTOE in 2030,

accounting for 28% of the world primary energy supply. This implies an annual growth rate of 1.6% over

the period 2000–2030, which is higher than the 1.3% observed during 1971–2000. The share of natural

gas in power generation will grow from the current 20% to 31% in 2030. Its share in final consumption

will not change.

Much of this incremental gas demand is expected to be used for generating power. As per

WEO 2002, the power sector’s use of gas will increase by 3.5% annually from 2000 to 2030. In

percentage terms, increase in the usage of gas for power generation will be the highest in Africa, Brazil,

and China.

Of the total incremental natural gas demand of 2118 MTOE over the period 2000–2030, the

Organization for Economic Co-operation and Development will account for 39% while the Asia-Pacific

region will account for 23%. (There are a few countries that overlap these two categories.) Within the

region, China is expected to account for 26% and India for 15%. Australia, Japan, and New Zealand will

together account for 11%, and South Korea is expected to contribute 9% to the incremental demand.

Thus, China and India are expected to be the key drivers of demand in the region, a role that

was till now played by Japan and South Korea. This is expected to result in significant changes in the

gas trade structure. Japan and South Korea have insignificant reserves and, hence, their demand was

met almost entirely through imports. Since these countries are located far away from Australia,

Indonesia, and Malaysia all imports were in the form of LNG (liquefied natural gas). This resulted in a

high share of LNG in trade in the region, unlike the trend in the West and the associated differences in

market structures, as detailed earlier. But the natural gas flows to India and China are expected to be a

mix of pipelines and LNG, and would thus change the market structure in these countries.

Given that gas demand in the region is expected to rise by 494 MTOE over the period

2000–2030, increased trade is expected, as the production is concentrated in Australia, Indonesia, and

Malaysia.

The following sections discuss in detail the flows expected in the region.

7. Regional cooperation in the Asia-Pacific region in natural gas This section divides the Asian region into three sub-regions as follows.

1 South-East Asia Brunei, Indonesia, Malaysia, Myanmar, The Philippines, Singapore,

Thailand, and Vietnam

2 North-East Asia China, Japan, North Korea, and South Korea

3 South Asia Bangladesh and India

7.1 South-East Asia

South-East Asia, consisting of 10 economies and situated along the South China Sea and the

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west coast of the Pacific, is the fastest growing economic consortium in the world. Its mean growth rate

of 3.6% per annum, over 1990–2000, is expected to persist till 2020. Five of these economies –

Indonesia, Malaysia, the Philippines, Singapore, and Thailand – have achieved a relatively high degree

of economic development and are the founder members of ASEAN (Association of South-East Asian

Nations). Between 1994 and 1998, Brunei Darussalam, Vietnam, Laos, Myanmar, and Cambodia also

joined ASEAN.

Seven South-East Asian economies – Brunei, Indonesia, Malaysia, The Philippines, Singapore,

Thailand, and Vietnam – are members of the APEC (Asia-Pacific Economic Cooperation), which

includes a working group dedicated to energy cooperation (the EWG—Energy Working Group) and

issues a CAP (Collective Action Plan), with an energy component.

South-East Asia is the world’s largest exporter of LNG, with 44.86% of the world’s total LNG

exports in 2001.

We now look at South-East Asian countries grouped as current exporters and demand centres

and review the future prospects for these centres (Table 3).

Country Reserves in early 2000 (billion cubic metres)

Reserve/production ratio in early 2000

Brunei 366 36 Indonesia 3790 55 Malaysia 2420 53 Myanmar 287 47 The Philippines 165 >100 Thailand 352 17 Vietnam 170 >100

Table 3 South-East Asian natural gas reserves and reserve/production ratios.

Source: IEA (2002)

Current exporters

a) Indonesia

Indonesia’s proven natural gas reserves are estimated to be between 3790 BCM and 2619

BCM by Cedigaz and the Oil and Gas Journal, respectively. These constitute 2.3% and 1.7% of world

production, respectively. Indonesia ranks first in South-East Asia among natural gas producers, though

its share in South-East Asian production has shrunk due to declining gas demand in the wake of the

Asian economic crisis in 1997.

The gas production facilities in Indonesia are concentrated on the islands of Sumatra and

Kalimantan. Java is the main demand centre. Small pipeline networks clustered around individual

demand centres, with few interconnections, characterize the Indonesian gas distribution infrastructure.

b) Malaysia

Malaysia’s state-owned oil and gas company, PETRONAS (Petroliam Nasional Berhad) has

discovered over 218 gas fields in the country, of which only 11 are active producers. Malaysia has the

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second largest gas reserves after Indonesia and is also the second biggest exporter of gas in the

region. It has a well-developed internal PGU (Peninsular Gas Utilization) network with a total length of

1688 kilometres that supplies mostly combined-cycle gas-fired power plants. These have emerged as

prominent components of Malaysia’s power generation efficiency and energy security goals.

c) Brunei

Brunei Darussalam has increased its proven gas reserves by 72.5% between 1994 and 2000.

A vast part of Brunei’s oil and gas reserves and production facilities is located offshore. Domestic use of

natural gas, mainly for power generation, is growing. Gas exports have grown over 1998–2001. Brunei

has long-term export contracts with Japan and South Korea extending from 1999 to 2013. It has a

920-kilometre domestic pipeline network linking gas fields with liquefaction plants.

d) Myanmar

Myanmar has about 10 onshore gas fields and two offshore fields with current proven reserves

of 287 BCM. A foreign investment law enacted in 1988 spurred exploration, leading to the discovery of

the two major offshore fields (Yadana and Yetagun). These account for the bulk of gas production,

holding 72% of proven reserves, and are almost entirely dedicated to export markets, with 3.54 MCMD

reserved for domestic use. Export from these fields has been conducted under a take-or-pay

arrangement with Thailand since 1998.

Demand centres

a) Vietnam

Vietnam produces a small amount of gas (1549 MCM [million cubic metres] in 2001). This is

used to meet domestic demand for power generation. It has proven reserves of 170 BCM as on 1

January 2000. Official estimates peg annual gas demand at 10–16 BCM during 2000–2005 and at

16–21 BCM between 2005 and 2010, which suggests that its current proven reserves are sufficient to

meet its demand until 2010.

b) Thailand

Thailand has estimated gas reserves of 352 BCM, about 94% of which are in offshore fields.

Production levels have increased by 12.6% per year between 1994 and 2000, but domestic supplies

are insufficient to meet the increasing demand (total demand in 1998 was 16.75 BCM, 80% of which

was in the power sector). Thailand has consequently entered into an import agreement with Myanmar

in 1998.

c) The Philippines

Gas demand in the Philippines is slated to increase due to the increasing use of CCGT plants

in power generation though the government also wishes to encourage gas use in all other sectors.

Proven reserves were 165 BCM in 2000, of which 70 BCM were in a single offshore field: the

Camago–Malampaya. Demand has been estimated to exceed 4 BCM per annum over 2002–2008 with

subsequent greater increases. With annual production in 2001 being a mere 11 MCM, the

demand–supply deficit is clear.

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d) Singapore

Singapore is the only South-East Asian country with no energy resources. Approximately 4.2

MCMD of gas is imported from Malaysia via the PGU pipeline to feed the Senoko power plant for power

generation. Other demand is met through bottled LPG (liquefied petroleum gas) provided by companies

like Shell and ExxonMobil (40% of demand) and ‘town gas’ manufactured from naphtha (60%).

Singapore plans to import more gas in the form of LNG or piped gas, primarily from Indonesia, with

which it has made arrangements in 2001 for 9.1 MCMD of gas.

Regional cooperation possibilities

a) Pipeline projects

Malaysia has one active cross-border pipeline link that connects peninsular Malaysia to the

Senoko Power Plant in Singapore, transmitting 4.2 MCMD. Singapore intends to increase gas-based

power generation (currently 20.5% of power generation); hence, demand along this channel will

increase. Prospective pipelines to be constructed will exploit the Malaysia–Thailand continental reef

within the JDA (joint development area) of these two countries. Two companies – both by the name of

Trans-Thai-Malaysia; one in Malaysia and the other in Thailand – were incorporated in 1999 to build

and operate, on an equal basis, a 363-kilometre pipeline and two GSPs (gas separation plants) in order

to exploit 13 gas fields with total estimated reserves of 347 BCM in the JDA. This project has, however,

been delayed due to protests over its environmental impact, and will now operate only in 2004. The

construction of a 20 000-hectare industrial zone in the vicinity of the pipeline will provide the necessary

demand linkage.

Indonesia has a gas pipeline network connecting its West Natuna gas field with 1260 BCM of

reserves to Singapore and is backed by a 22-year supply contract with a daily volume of 9.1 MCM.

Another 450-kilometre pipeline to be completed by August 2003 will connect Sumatra, which has 854

BCM of reserves, with Singapore providing a daily supply of 5.6 MCM.

No cross-border pipelines exist at present in Brunei but it has agreed in principle to be part of

the TAGP (Trans-ASEAN Gas Pipeline), which is discussed in a subsequent section.

Myanmar supplies 12 MCMD of gas to Thailand via a 649-kilometre pipeline from its offshore

Yadana gas field to the Ratchaburi power plant in Thailand. In 2000, another linkage was made to this

pipeline from its Yetagun gas field, adding 5.6 MCMD of supply. Pipelines have also been built in 2001

linking the Yetagun gas field to combined cycle power units in Ratchaburi and Wangnoi, in Thailand.

These power projects, when fully completed, are likely to be a stable, long-term export market for

Myanmar.

b) Future pipeline prospects

The most prominent prospect in pipeline cooperation in the ASEAN region is the TAGP (Figure

14). This is to be a 4500-kilometre network of cross-border pipelines to interlink the domestic pipeline

networks of ASEAN countries. This is estimated to cost 7 billion dollars when it is completed in 2020.

One prominent component of the TAGP is the utilization of the Indonesian Natuna gas field. This is one

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of the largest natural gas fields in the world, and has a unique central location with regard to all

South-East Asian countries and demand centres in South China, Japan, and South Korea.

Apart from serving significant current and future intra-regional demand centres such as

Singapore and Thailand, the TAGP may be extended to Chinese Taipei and South China (the

Changjiang region around Shanghai) that are large and where the demand is growing. Deliveries to

these regions could be routed through the Philippines. India is being considered to be a potential

interconnection for the TAGP via Myanmar and Bangladesh, as India is likely to face geo-political

problems in obtaining pipeline gas from Central Asian countries.

Figure 14: Trans-ASEAN gas pipeline

Source: Stern (2002)

c) Liquefied natural gas projects

LNG is a mature industry in South-East Asia. Brunei, Indonesia, and Malaysia began exporting

natural gas as early as 1973, 1977, and 1983, respectively. Indonesia is the world’s single largest LNG

exporter, totalling 34 BCM in 2001. Malaysia ranks third with 22 BCM. Together, South-East Asia

accounts for 45% of the world LNG trade.

Due to high costs of transporting it, LNG trading markets are strongly regional. Almost the

entire LNG exported from Indonesia, Malaysia, and Brunei is consumed in South-East and North-East

Asia, with the latter consuming more. Japan and South Korea are the current largest markets for

South-East Asian LNG exports. South Korea has few energy resources and its rapid growth has

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accelerated energy demand in its industrial and residential sectors, it is also the second largest

importer of LNG.

Japan and Korea are expected to need more gas than what they have reserved, and are

expected to import a significant part from Indonesia and Malaysia (Figure 15). Suppliers will exploit the

strategic location of the Natuna gas field. The TAGP is likely to be extended to South China’s

Chingjiang delta region, so that gas may be re-exported to South Korea and Japan via pipeline.

India and China are also likely to emerge as significant LNG markets for South-East Asia, as

detailed later.

Figure 15: Japan and South Korea’s natural gas deficit

Source: APEC (2000a)

7.2 North-East Asia

Outline

North-East Asia consists of China, the world’s second largest energy consumer, and Japan

and South Korea, the world’s largest LNG importers. Natural gas is underutilized in North-East Asia

compared to other regions, because it lacks processing and pipeline infrastructure. Other reasons may

be the historical near-exclusive reliance on LNG and the lack in volume of consumption that would

justify investment.

China has, from the mid 1990s, promoted the ‘Pan–Asian Continental Oil Bridge’ of gas and oil

pipelines to link China with the Middle East, Central Asia, Russia, South Korea, and Japan to achieve

energy security. It aims to be a refining and distribution centre, linking Middle Eastern and Central Asian

crude oil markets to consumer markets in East Asia. This, along with the proposed formation of a

‘Northeast Asian Energy Community’, as suggested by Russia in 1997, seems to indicate greater future

cooperation in energy in this area.

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a) China

Natural gas has not been a major fuel in China thus far, but this could change. China is

expanding its infrastructure to exploit its big gas

reserves, which stood at 1.36 TCM in 2002, and the resulting environmental benefits. Gas currently

accounts for three per cent of the primary energy consumption in China (mostly as feedstock), but

consumption is forecast to triple by 2010, making the country a major demand centre.

China’s large gas reserves are concentrated in its western and north-central regions.

Significant investment in pipeline infrastructure is required to carry it to cities in East and South China,

which are the main demand centres. The 4167-kilometre, 18-billion-dollar ‘West-to-East Pipeline’

project intends to connect gas deposits in the Xinjiang province to Shanghai, picking up gas from the

Ordos gas field on the way. However, the estimated 20-year reserve life of these gas deposits is likely

to render this project unviable.

China is also increasingly investing in finds of offshore gas, mainly in the East China Sea, that

has so far yielded 45 BCM of reserves.

b) South Korea

South Korea currently relies on imported LNG to meet its entire demand for natural gas. A

minor deposit containing 5.66 BCM of gas is scheduled to go into production this year (2003). It is the

world’s second largest LNG importer. Natural gas meets around 10% of South Korea’s primary energy

consumption. This is split evenly between the power generation and residential sectors. Most of the

LNG used comes from Indonesia and Malaysia (57%), and smaller quantities from Brunei, Oman, and

Qatar.

South Korea is increasing capacity at its two LNG terminals, and is constructing a third one, to

be operational by 2005. Gas consumption grew by almost 50% between 1998 and 2001. If this trend

continues, a significant gap between future demand and the amount reserved under long-term LNG

contracts will occur.

South Korea has held discussions with China, Russia, and BP (British Petroleum) about the

possibility of importing natural gas from Russia’s huge Kovytka gas field near Irkutsk. While China

would be a major importer of gas through the pipeline, the project could be made more economical by

adding a link to South Korea, which currently gets the vast majority of its natural gas by tanker as LNG.

North Korea is one possible route for the pipeline link to South Korea, and would be less expensive

than the subsea alternative.

c) North Korea

North Korea meets its domestic energy needs almost entirely through coal and hydropower. In

1999, coal accounted for 86% of primary energy consumption. Significant hydrocarbon reserves have

not been encountered in North Korea, though the West Korean Bay may contain crude oil.

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d) Japan

Japan has about 39.66 BCM in proven gas reserves with possibly more in seabed reserves.

With minimal domestic gas production, 97% of its demand is met by LNG imports from South-East Asia

(36% from Indonesia and 19% from Malaysia) and the Middle East. Japan’s dominant demand sources

are power generation, fertilizer feedstock, and City Gas. (City Gas consists of liquefied natural gas,

indigenous natural gas, coal, liquefied petroleum gas, and naphtha as delivered to over 25 million

consumers in households and industry.)

The latter category of demand has increased at 6.5% per annum between 1990 and 2000 while

gas demand for power generation has levelled off (due to the Japanese economic slowdown and the

commissioning of a number of coal- and nuclear-based power generation plants). Japan currently lacks

a pipeline system to serve its urban demand centres efficiently.

Environmental and energy security concerns are likely to increase natural gas demand in

Japan to about 13% of primary energy consumption in 2010. This will create a demand–supply gap of

about 22.5 MT.

Pipeline gas supply possibilities in North-East Asia

a) China

The pipeline supply alternatives for China are (1) East Russian Gas, (2) Sakhalin Island, (3)

Caspian Sea region and Central Asia, and (4) South-East Asia.

East Russian gas: There are three possible routes for the pipeline supply of Russian gas to China.

The BP-led consortium is developing the Kovytka field in East Siberia (1.38 TCM of reserves) to link

to north-eastern China. Two other routes have been considered. One bypasses Mongolian territory and

will be between 2092 and 3219-kilometre long, depending upon the Mongolian factor. The other, being

developed by the Sakha consortium, is a 2736-kilometre pipeline link between the East Siberian

Chayandonovskoye field (1.21 TCM of reserves) and the Xingjiang province in North China. The

delivered cost of gas for either option is lower than that of the Chinese West–East pipeline (an average

of 1.75 dollar per MMBTU as against 2.25 dollars per MMBTU. The construction cost estimates are

between 6 and 10 billion dollars.

Sakhalin Island: No direct pipeline linkage between Sakhalin and China has been considered

yet, as the East Siberian option is easier. This is because the distance is less; Sakhalin is close to the

export market in Japan, and the icebound seas around Sakhalin make pipeline construction difficult.

The Caspian region: ExxonMobil, Mitsubishi, and China Petroleum have submitted a feasibility

study for the world’s longest natural gas pipeline from Turkmenistan (2.86 TCM of proven reserves) to

Xinjiang in China via Uzbekistan and Kazakhstan—an estimated length of 6696 kilometres and a

capacity of 30 BCM per year. The project’s estimated cost of 10 billion dollars, together with geopolitical

issues raised by the number of countries of transit, has diminished interest in it.

An interesting point to note here is that pipelines from the Caspian region could feed into the

West–East trans-China pipeline from the Xinjiang province onwards. It could be more viable because

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greater reserves would be available.

South-East Asia: This would involve an extension of the proposed 4500-kilometre TAGP to the

Yunnan Province in South China via Vietnam and onwards to other demand centres in South China,

taking advantage of the location of the vast Natuna gas field in the South China Sea.

b) Japan

Japan’s natural gas pipeline import options are (1) Sakhalin Island, (2) re-exported gas from

China, and (3) re-exported gas from South Korea.

Sakhalin Island: Sakhalin Energy (Sakhalin-1) – a consortium of ExxonMobil (US), Rosneft

(Russia), and ONGC (India) – proposes to link three gas fields in Sakhalin to Japan via a 193-kilometre

pipeline to Sapporo on Japan’s northern-most island of Hokkaido. The operation of this route is to

commence in 2008 with exports of 10.19 BCM per year.

China re-export: The proposed pipeline linking the Caspian region to the Chinese coast could

have an extension to Japan, as could the proposed ‘West–East’ pipeline. However, two issues arise

here: (1) the onshore route for a pipeline from China is likely to lie through the densely populated

Osaka–Tokyo region where the cost of pipeline construction would be extremely high; (2) China may

charge a considerable ‘transit fee’, effectively reselling the gas as a merchant; this may raise the

delivered cost of gas by 25% or more.

South Korean re-export: Re-export options from South Korea may prove difficult as any pipeline to

South Korea must pass through both China and North Korea, leading to both transit fee and political

problems.

c) South Korea

The only economically viable supply option for South Korea is to obtain gas from the Kovytka

gas deposit in Eastern Siberia. The pipeline, that could serve China as well, is estimated to have a

supply of 28.32 MCM per day, but will have to necessarily pass through North Korea. Although the two

Koreas agreed in 2001 to conduct a joint feasibility study on the project, recent tensions between them

have cast doubts over the project.

Liquefied natural gas in North-East Asia

China’s current consumption levels of natural gas are rather small, though slated to increase

greatly. Its own reserves of gas are also considerable, though largely untapped. LNG has not been

explored on an urgent basis in China. Its first LNG terminal relying on gas from South-East Asia is to be

established in Guangdong Province in South China by early 2005. LNG makes better economic sense

than pipelines for many of China’s coastal cities and demand centres close to the sea.

Japan has three LNG import sites close to the three large city demand centres of Tokyo,

Nagoya, and Osaka. Its import sources are also fairly diversified in terms of import share: Indonesia

(36.4%), Malaysia (19.8%), Australia (14.6%), Brunei (10.8%), UAE (9.1%), Qatar (6.7%), and the

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Middle East (2.6%). This pattern is likely to persist as it is structured around long-term contracts. Japan

suffers from an inadequate trunk-line system for LNG distribution within the country, which is currently a

high investment priority. Japan has strong LNG linkages with Australia, which has 2520 BCM of

reserves (the second largest in the Asia-Pacific region) and is likely to find greater reserves (252 BCM)

in large offshore deposits (the Sunshine and Troubadour fields) that are likely to be tapped by

2006/07. Australia is developing FLNG (floating LNG) facilities in its offshore fields in a bid to double its

current share of the Asian energy market by 2010. It aims to commission three of the estimated 10 new

LNG trains that will be required to meet new Asian gas demand, by 2010.

South Korea is the world’s second largest LNG importer via its two terminals at Pyongtaek and

Inchon. It plans to construct another one at Kwangyang by 2005. It has a reasonably diverse basket of

import sources; Indonesia, Malaysia, and Qatar account for 62% while Brunei and Oman account for

the rest. The two Middle Eastern sources have come online relatively recently (Qatar in April 1999 and

Oman in April 2000). Exports from the Middle East are forecast to increase and new sources, such as

Canada, are likely to be tapped. This will bring about a greater diversification of sources.

7.3 South Asia

South Asia, or the region known as the Indian subcontinent, accounts for 22% of the world’s

population but consumes a mere 5% of world energy. Countries of the region are linked via an

organization for economic cooperation and a preferential trading agreement called SAARC (South

Asian Association for Regional Cooperation). Energy cooperation, however, is yet to materialize, due to

political considerations between India and Pakistan as well as between India and Bangladesh. With

respect to natural gas, it is significant that this region contains both one of the largest potential

emerging markets for natural gas in India and a potential major natural gas producer in Bangladesh, in

very close proximity.

Demand centre

a) India

India’s consumption of natural gas has risen faster than that any of other fuel over 1995–2001,

mostly due to increased usage in power generation (Figure 16). The GoI (Government of India) has

chosen to encourage the development of gas-fired power plants due to inherent advantages of using

CCGT as detailed above.

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Figure 16: Natural gas consumption in India

Source: IEA (2002)

Future expansions in fertilizer production, prompted by food security considerations, are also

likely to use gas as feedstock. The conversion of naphtha-based units to gas is planned as and when

the gas is available. All these will increase the demand for gas in the future.

The Tenth Five-Year Plan released by the GoI has projected natural gas demand at 47.45 BCM

in 2006/07, rising to 64 BCM in 2011/12. Despite the recent find of 196 BCM of gas in the

Krishna–Godavari river basin in South India, augmenting India’s 763 BCM of reserves, domestic supply

is unlikely to keep pace with demand. The increased prospects of Indian sedimentary basins in the

aftermath of this discovery promise to attract more investment in the E&P (exploration and production)

sector (Box 2).

Box 2 Reliance’s gas discovery and gas import options for India

In October 2002, the RIL (Reliance Industries Limited) announced a massive gas

discovery in the block KG-DWN-98/3 along the East Coast of India, which was awarded to the

RIL–NIKO consortium during the first round of the New Exploration and Licensing Policy. The RIL

claims that this gas block holds proven reserves of 198 BCM (billion cubic metres) and

recoverable reserves of 141 BCM and that the field can produce at the maximum rate of 40 million

cubic metres per day. The discovery is significant because it increases India’s current proven gas

reserves by 18%. When the first gas is delivered in about three years’, production will increase by

52% over current levels.

The discovery put a question mark over the proposed LNG terminals planned along the

eastern coast, most prominent among them being the IOC (Indian Oil Corporation) terminal

planned at Kakinada, though the IOC still maintains that this terminal is feasible.

The gas find also has the potential to impact the market for Bangladesh gas, since one

section of the Bangladesh–India pipeline is to run to the South. Eastern India, which borders

Bangladesh, has huge coal reserves and this will reduce the price of gas in the region. Hence, the

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most lucrative markets are northern and southern India. Though RIL’s gas will probably be

consumed in southern India, there is a slight chance that the gas might flow west wards and

connect to the HBJ (Hazira–Bijaipur–Jagdishpur) pipeline, thereby catering to the northern market

as well. This scenario will become inevitable if more such gas discoveries are made in the region.

Hence, the critical issues now for all the projects planned to import gas into the country

are timing and the pricing benchmark. If more gas reserves are found along the eastern coast,

selling imported gas benchmarked to international crude oil prices will become very difficult.

Supply centre

a) Bangladesh

There is considerable uncertainty regarding the level of gas reserves in Bangladesh. Current

estimates by the government-owned oil and gas monopoly, Petrobangla, put net reserves at 461 BCM,

but the USGS recently estimated that Bangladesh might contain an additional 909 BCM of gas,

perhaps in several offshore deposits. Bangladesh may thus have the potential to become a major gas

producer.

Gas exports are a controversial issue in Bangladesh. Both its major political parties feel that

exports should occur only if proven reserves can cover 50 years of domestic demand. A formal

proposal had been submitted by Unocal to link Bangladesh’s largest gas field (Bibiyana) via pipeline to

India’s HBJ network, but little progress has been made so far.

Pipeline gas supply options in South Asia

Several pipeline supply options have been considered for India.

Oman–India Pipeline: This 5-billion-dollar pipeline project, proposed by the OOC (Oman Oil

Company), envisaged two deep-sea pipelines from Oman’s Sayh Rawl gas field to Gujarat. However, a

study declared the project infeasible because of technical problems posed by the depth.

Iran–India Pipeline: Two alternatives have been considered: (1) an onshore pipeline through

Pakistan and (2) an offshore pipeline skirting Pakistan’s territorial waters. However, political

considerations may halt the former, and difficulties with the deep-sea route from Iran may cause

problems with the latter.

Central Asia Pipeline: This pipeline proposes to link Turkmenistan with Pakistan via Afghanistan; an

extension to India may be desirable for the feasibility of the pipeline. A consortium led by Unocal, called

Central Asia Pipeline Ltd, examined a proposal to construct a 1250-kilometre pipeline from

Turkmenistan’s Dautelabad field to Multan in northern Pakistan, along with an option for a

600–700-kilometre extension to North India. The project was to cost 2–2.5 billion dollars. The political

unrest in Afghanistan led to the rejection of this proposal. Since then, the possibility of a

Turkmenistan–Iran pipeline with an extension to India has been considered, which, however, runs into

the same problems.

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Bangladesh–India Pipeline: Two proposals have been given in this regard: (1) Unocal’s 1350-kilometre

pipeline connecting the Bibiyana gas field to the HBJ pipeline at a cost of 910 million dollars and (2)

Shell’s link between the Sangu gas field to the HBJ pipeline. Both these ventures have run into strong

political opposition following the general election in Bangladesh.

Other pipeline links: These include a link with Myanmar through Bangladesh and even a link with

the TAGP system. The former requires Bangladesh’s cooperation and needs greater gas reserves in

Myanmar to become viable. The current reserve/production ratios in South-East Asia may not make the

latter project feasible. There is also a proposal to swap Indian gas produced in Tripura with

Bangladeshi gas, but not much progress has been witnessed on this either.

Liquefied natural gas supply possibilities

Due to declining costs, importing natural gas into India via sea after liquefaction became an

attractive prospect in the 1990s, given the demand–supply gap expected in the future. As of now, 10

LNG terminals have been planned in the country, along both the eastern and western coasts. The

terminals planned along the western coast will source LNG primarily from the Middle East, with the

exception of Shell’s terminal at Hazira; those planned along the eastern coast will source LNG from the

Asian market. Considerable ground progress has already been made on three terminals at Dabhol,

Hazira, and Dahej. In fact, the erstwhile Enron’s terminal at Dabhol would have started taking deliveries

under different circumstances.

Although many companies, both Indian and multinational, have stakes in the Indian LNG

market, there are a few disconcerting issues. One is that of price. Marketing companies are finding it

increasingly difficult to sell imported gas at prices linked to the international crude oil price. With the

prospects of more indigenous gas that would cost less on the horizon, it is likely that negotiations

between buyers and sellers would take time.

LNG imports into the country are expected to amount to 7 MTPA (million tonnes per annum),

rising to 15.83 MTPA by 2010. This, along with indigenous gas and pipeline imports, makes competition

between LNG and natural gas imminent. Proper legislation will be required to sort out clashes of

interests; work on such legislation has already started.

8. Looking ahead at the natural gas market Insights emerging from the above sections may be summarized in the following points.

• Indian and Chinese markets will play an important role in determining the strategies and

guiding the direction of the Asian natural gas market.

• Australia and Indonesia will remain key supply centres.

• Intra-regional trade will increase in importance, as more nations participate in the

exchange.

• Inter-regional trade will also assume significance (Annexe 2).

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• As supply sources grow and spot trade assumes significant proportions, buyers will be able

to negotiate better terms (Annexes 3 and 4).

• Deregulation in the downstream industry will play an important role influencing prices,

contractual obligations, and market structure.

As detailed in Box 1, there is no true global gas market. But, can its emergence be expected?

The next few decades will see more gas flows from Russia and Central Asia into China and India,

expected to be major consumers in the region (Figure 17). This will help integrate markets since

Central Asia and Russia will also supply more gas to Europe (Box 3). Hence, pricing will reflect

competitive pressures to some extent. Australia will also supply natural gas to the US, whose

dependence on imports is likely to increase (Annexes 5 and 6).

Box 3 Role of Central Asia in the Asian gas market

The Middle East is the Asia-Pacific region’s largest supplier of both oil and gas. This

dependence has forced consumers to look for an alternative supplier. One region that everyone is

looking towards is Central Asia. Strategically located vis-à-vis Russia, the Middle East, the

Asia-Pacific region, Iran, Turkey, and Afghanistan, its geopolitical importance is obvious. The

region’s gas output is projected to be 175 BCM (billion cubic metres) in 2010 and 206.7 BCM in

2015 with major contributions from Turkmenistan, Uzbekistan, Kazakhstan, and Azerbaijan.

On the one hand are Central Asia’s huge natural gas reserves (Azerbaijan’s Shah Deniz

field is thought to be the largest natural gas discovery worldwide since 1978) and on the other

hand are the geopolitical challenges that would have to be overcome if this region has to be

connected to the demand centres.

The major export option envisaged is the Central Asia Pipeline, traversing from

Dautelabad field in Turkmenistan to Multan (Pakistan), moving 19.83 BCM of gas annually and

costing 2 billion dollars. Experts feel that this will be feasible only if it is extended to India. But,

India is sceptical of any pipeline coming via Pakistan due to obvious security concerns. Then there

is the China gas pipeline, which would extend from Turkmenistan to Xinjiang and transport 28.3

BCM of gas every year. A preliminary feasibility study has been conducted by ExxonMobil,

Mitsubishi, and CNPC (Chinese National Petroleum Company), and is under review.

One major factor influencing Central Asia’s reserves will be Russia, which has been trying

to ensure that existing pipelines continue routing through it. And, as Wu and Fesharaki (2002) put

it, Central Asia’s potential may be great, but it is not going to be another Middle East. Central

Asia’s link to South Asia is complicated because of instability, lack of infrastructure in the region,

and political imperatives.

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Keeping these observations in mind, what can be the future gas scenario in the Asia-Pacific

region? More specifically, in view of the growing possibilities in trading, most of them involving diverse

countries, what role can be envisaged for regional groupings like the ASEAN, SAARC, and APEC?

Trade, either in commodity or in service, has to be based on commercial considerations if it is

to survive the test of time, and trade in natural gas is no different. Buyers and sellers would have to

settle for terms and conditions that suit them all. Regional political groupings can provide a forum that

would bring buyers and sellers together having equal access to information.

But, does this mean that commercial groupings, like an LNG Buyers’ Forum, would supersede

any region, would provide a better opportunity for both buyers and sellers to interact because such a

forum will be free from political overtones, and would be based on individual interests? Such a forum

will increase the Asia-Pacific region’s power to bargain with suppliers, and will prove very important

when inter-regional trade becomes significant.

Figure 17: Proposed pipelines from Russia and Central Asia

Source: Stern (2002)

However, because political imperatives cannot be overlooked, regional groupings like the

SAARC may provide an opportunity for countries to meet and discuss solutions to political

impediments.

The formation of such a global market cannot proceed without an integrated gas prices across

markets. Although it seems unlikely that global gas price will be linked to Henry Hub prices, new pricing

formulae will have to evolve. Linking gas prices to volatile crude oil prices made sense in earlier days

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when the prime focus of the explorer was to find crude oil and, hence, the prices of gas found were

linked to crude oil. But, with gas becoming an increasingly important fuel, this mechanism will no longer

suffice. Moreover, because deregulation in the downstream industry is squeezing margins, such a link

to crude oil prices will increase the buyer’s market risk. However, prices may become increasingly

localized, competing with alternative fuels, maybe gas itself, in each market.

Benchmarking gas prices to prices prevailing in a downstream industry like power, at least

during the transitional period, is also an option. This might be adopted in countries like India, to help the

nascent gas industry grow. First-degree price differentiation may also set in, with different prices being

charged to different consumers. In this context, with the reforms aimed at rationalizing the market,

domestic fiscal and pricing regimes will play an important role. Streamlining taxes and taking away

government intervention from the market may be difficult, but it will have to begin in order to foster

efficiency.

8.1 Deregulation and its impact

Many countries in the Asia-Pacific region are experiencing deregulation in key infrastructural

industries, the most important of which is power. Because the power sector is the key consumer, its

deregulation is bound to impact the natural gas market in the region significantly.

Deregulation of downstream industries will result in different contractual obligations. Japanese

companies were willing to pay premium prices for natural gas in return for security of supplies based on

long-term contracts with stringent offtake obligations. But, with deregulation in the Japanese electricity

markets, utilities now argue that they can no longer accept the traditional 20-year contract, and are

pressing for a basket of short-, medium-, and long-term arrangements. When Tokyo Gas and Tokyo

Electric renewed their contracts with Malaysian LNG, they were able to obtain new terms that not only

reduced their prices by around 5% but also shrunk the share of their long-term contracts to only 20% of

the total quantity. The South Korean market is also poised for significant changes. Impending

deregulation in their gas and power industry promises to introduce such flexibility in contracts.

Increasing vertical integration of gas sellers and buyers will also be important, especially as a

tool to help nascent markets like India take off. This is because of the changes in the risks inherent in

the LNG business. When the LNG market was in the nascent stage, the risks were almost absent. But

with several buyers and sellers with low credit standing joining or expected to join the ranks, business

risks will grow. This will necessitate important changes in business models that are currently prevalent.

This will also be an imperative to some extent if the sellers have to monetize their gas reserves and

make the deal financially attractive for banks, especially so if the deal involves low-creditworthy buyers.

Deregulation in the power sector in key markets like India and Japan has made it possible for the

anchor load of an LNG terminal to be provided by a merchant power plant that may or may not operate

at all times, given the competition in the market. Such a possibility would also be taken into account

while negotiating contracts.

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Such deals will also necessitate new supply and purchase contracts with innovative clauses to

deal with low-creditworthy buyers. The deals will become more complex, but more transparent in

allocating risks among the stakeholders. The existing business model is asset-based, long-term, and is

focused on locking in specific supply with specific demand. This needs to be changed. Such changing

nature of transactions highlights the most invaluable advantage of the LNG option—flexibility to change

cargo destination according to market opportunities.

This last point is important. Earlier, negotiated contracts had restrictive clauses whereby

third-party sales were not allowed. Deregulation and cheaper LNG trains now mean that buyers do not

make tough offtake commitments that increase the market risk for them, and sellers confidently

continue construction even if the full capacity of the LNG train has not been contracted. This has

resulted in more short-term LNG coming into the market (Figure 18).

Figure 18: Growth in short-term liquefied natural gas trade

Source: BP (2002)

8.2 Other developments

The emerging gas-to-gas competition in markets like India will also encourage buyers to

contract minimal supplies on a long-term basis and buy mostly on spot, although from the same LNG

train. An important issue related to gas-to-gas competition is the cost improvement that has occurred in

the LNG industry. Between 1996 and 2000, the average unit liquefaction cost was 230 dollars per tonne,

down from 560 dollars per tonne between 1986 and 1990. The price of new LNG tankers has also

dropped from 220 million dollars to 155 million dollars between 1996 and 2000. This has been coupled

by a rising second-hand market for tankers.

The effective price of LNG to major markets of Japan and Korea has not shown a

corresponding fall (Figure 19) due to the current LNG pricing formula that links LNG price to a crude oil

basket.

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The formula employed by Japan, Korea, and Taiwan is : P = aX + b + S where P is LNG price, a and b are constants and X

represents crude oil price. The S curve is meant to moderate the price when it is above (or below) a certain zone (IEEJ 2002).

Figure 19: Liquefied natural gas prices to the Japanese and Korean markets

Source: IEA (2002)

Other important changes in the Asian piped gas market may occur. Major intra-regional

projects like the TAGP promise to foster better intra-regional ties and increase supply security. Such

projects make for the first step towards creating a regional energy market like those in Europe. But, for

this to materialize, geographical, technical, and socio-political challenges have to be overcome.

Advances in deep-water gas pipeline technology are required to improve the economics of pipelines in

comparison with that of LNG trains. As more and more hitherto undeveloped regions are explored,

technical advances will be necessary to deliver this gas to markets at competitive prices.

The relative economics of pipelines and of LNG are summarized in Figure 20. It indicates that

piped gas from the Irkutsk region in Siberia is as economical for North-East Asia as LNG from Sakhalin.

Another key issue in the comparison between PNG (pipeline natural gas) and LNG for Asia is

that of economies of scale; low unit costs for delivered gas are available only when it can be delivered

in large volumes. Few cost or efficiency breakthroughs can be expected from additional commerce in

LNG within this region, because the economies of scale in LNG production and transport are limited

relative to that of PNG. Unless natural gas can take full advantage of economies of scale, it is not likely

to gain a decisive cost advantage over less secure or environmentally desirable fuels such as oil or coal.

The use of 142-centimetre pipelines is likely to significantly enhance economies of scale. Unfortunately,

the current East Siberian and Sakhalin natural gas reserves are not sufficient to make this possible;

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further development is required.

Figure 20: Transportation costs by type of North-East Asia

Source: APERC (2000)

Traditionally, natural gas has been used to generate electricity in the Asia-Pacific region—India

uses some for producing urea. However, several new markets are poised for high growth, most

prominent being the transport sector. The city of New Delhi is the prime example of this, but availability

of resource and its opportunity costs are two criteria on which such uses of natural gas can be

evaluated. Another option is to convert gas into conventional fuels using gas-to-liquid technology

(Box 4).

Box 4 Gas-to-liquid technology

The GTL (gas-to-liquid) technology based on the Fischer-Tropsch process was invented

in 1923. It has been tested on a large scale by a few multinational oil companies. About 338 750

barrels per day of capacity in this technology is likely to be added by 2005–07 and a further 805

250 barrels per day of capacity is proposed. It is claimed that the GTL technology is financial

viable at a crude oil price of 14 dollars per barrel, a gas feedstock price of 0.50 dollars per MMBTU

and a plant size of 70 000 barrels per day. The key factor that will determine the price commanded

by conventional fuels produced through GTL is, however, the sulphur specifications in these fuels.

A move towards ultra-low sulphur diesel or zero parts per million sulphur diesel would increase

refining costs enough to make GTL more competitive.

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9. Conclusion Natural gas in the Asia-Pacific region is poised for higher growth, spurred by security and

environmental concerns. However, enabling factors that pave the way for increased regional

cooperation among the nations should be nurtured. Increased integration in the worldwide natural gas

market will make the market more volatile but secure. Institutional and contractual changes are

required in order to continue this process of integration and growth. Deregulation in the downstream

industry will play the enabling role. The Asia-Pacific region may be years away from having a regional

energy market, but a start can be made with natural gas as the catalyst.

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Report on Special Project 1-A Appendix - B

Storylines on

Asia’s Natural Gas Perspectives

Lead Author Ken Koyama

The Institute of Energy Economics, Japan Japan

Stories expressed in this report are descriptions of plausible future developments concerning the future

for Asia’s gas infrastructure. The International Gas Union and the core team do not necessarily have

any opinion about the desirability or otherwise, or the probability of the futures portrayed, which are

intended to provide the reader with useful food for thought.

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Storylines on Asia’s Natural Gas Perspectives

Lead Author Ken Koyama, The Institute of Energy Economics, Japan

Core team members:

Ken Koyama, The Institute of Energy Economics, Japan

Takeo Suzuki, The Institute of Energy Economics, Japan

Koji Morita, The Institute of Energy Economics, Japan

Ryo Fukushima, NOC of WGC2003

Koji Okuda, NOC of WGC2003

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1. Introduction Natural gas makes up merely 10% of the primary energy supply in Asia1 and the natural gas

industry is still taking shape. However, countries in Asia are now adopting a policy of shifting from the

current energy systems to environmentally benign natural gas to support their economic growth, on the

one hand, and also to improve their environmental quality. Natural gas is attracting much attention

today because of its improved efficiency thanks to technology development and versatile methods of

use, such as fuel for natural gas vehicles and distributed power generations.

On the other hand, obstacles for adopting natural gas include the initial high cost of setting up

the transportation system and the need to build up the volume of demand. However, geopolitical issues

between neighboring countries, which used to characterize Asian politics, have improved since the end

of the 20th century because of progress in political stability and economic development.

We held a workshop with members from Asia’s natural gas industry, energy researchers,

experts on the global environment, and experts on energy related technology, and we have developed

the impression that the future of natural gas in Asia will be decided by the development of infrastructure.

This means that natural gas usage and its role in Asia will differ greatly depending on whether natural

gas networks spread across multiple countries or are simply used for transporting natural gas to

neighboring consumers as they are today.

Key issues and driving forces that are both important and sources of uncertainty and affect the

development of natural gas infrastructure until 2030 are examined based on the results of this

workshop. Finally, by determining some of the driving forces, we developed two different future stories

for natural gas use, and completed them as natural gas storylines for Asia using feedback from the

second workshop.

In this report, driving forces and their impact on natural gas infrastructure are described at the

beginning as the results from two workshops. Next, based on the results, two storylines “Ebb & Flow”

and “Tsunami” are described along with brief summaries for Asia and regional stories for some typical

areas.

We considered these two storylines to be equally plausible, rather than adopting one story as

more probable or preferable. The role of natural gas in each story differs greatly.

1 “Asia and Oceania” covers Japan to Pakistan, from east to west, and Mongolia to Australia and New Zealand, from north to south. Hereafter, Asia expressly refers to the Asia and Oceania region.

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2. Driving Forces behind Natural Gas Perspectives in Asia Natural gas in Asia (referring here to Northeast Asia, Southeast Asia, South Asia and Oceania)

constitutes only 10% of the primary energy supply, but the potential for future natural gas usage is said

to be enormous. In Figure 1, the major driving forces that affect natural gas development in Asia are

shown sorted by economic, political, business, environmental, and technological perspectives. In this

figure, the horizontal axis indicates the certainty or possibility of each issue. The perspective of

“population” is not included, but has a great affect on energy usage. Generally speaking, population is a

known factor over the next twenty to thirty years.

Tec

hn

olog

y

Uncertain CertainPopulation

Fuel Cell

MicroGT

EfficiencyImprovements

Spread of Tech.

GTLHydrate

India China, S.E. AsiaEconomic Growth

Eco

nom

y

Asia FTA

Pol

itic

s

Energy SecurityEnergy Share

Supplier Share

Local/RegionalEnvironment

COP IIGlobal

Bus

ines

s Foreign Invest.City Gas

Competition btw SuppliersCompetition btw PL/LNG

Regional Stability

CoalBed

Methane

Emission Trading

ASEAN Pipeline

Hydrogen

Figure 1: Driving forces behind the future of natural gas.

From the above issues, driving forces that have a high uncertainty factor but have a great affect

on developing natural gas infrastructure are examined in workshops with members who were chosen

as experts in the five perspectives above.

As a result, the following three issues are chosen as the most significant driving forces

affecting future infrastructure.

1. Security issues

2. Global warming

3. Technology

Figure 2 shows a map of their importance from the standpoint of uncertainty and impact.

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Will developing countries participate in taking

measures against global warming?

How security issues affect the preference for gas?

Will technological innovation expand the use

and demand for gas?

Will installation of multilateral infrastructure (PL) progress smoothly?

Impact

Uncertainty

YES

NOWill developing countries

participate in taking measures against global

warming?

How security issues affect the preference for gas?

Will technological innovation expand the use

and demand for gas?

Will installation of multilateral infrastructure (PL) progress smoothly?

Impact

Uncertainty

YES

NO

Figure 2: Branch points for stories.

The following subsections describe how these issues affect the future development of natural

gas.

2.1 Security issues

The main sources of energy supply in Asia today are coal and oil, which are mostly produced

within the region, and some resource poor countries have relied heavily on oil imports from the Middle

East. Furthermore, oil production in Asia will become unable to keep up with oil demand in the very

near future and Asia will become a major importer of oil. Centers of demand in Asia are mostly located

in coastal areas, so oil imports will mainly rely on tankers from the Middle East, a region with enormous

resources.

Security concerns originate from the dependency on oil from one region, and future change will

depend on whether action is taken toward avoiding a disruption of imports. Varying areas of imports

and changing the nature of the energy system are the main methods for enhancing energy security.

However, oil resources are mostly located in the Middle East. This report focuses on a discussion of the

possibilities for changing the nature of the energy system. Two stories are considered. One story

assumes that energy security concerns cause an energy shift towards natural gas, and the other

assumes a world where energy supply is the top priority and sufficient security precautions are not

taken.

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2.2 Global warming

Global environmental issues, such as global warming, are thought to be caused by greenhouse

gases, especially CO2, emitted from human economic activity. Further energy consumption in Asia

along with progress toward economic growth will increase CO2 emissions in this region, making

necessary renewal of energy facilities, a change in energy sources, and energy savings.

Most Asian countries today have committed to the Kyoto Protocol proposed at the 3rd COP

Meeting of UNFCCC. The protocol requires signatory countries to cooperate to meet the emission

limits assigned to Annex-I countries. Thus, if global warming countermeasures suit the domestic

environmental policies (desulfurization and denitration) of Asian countries, it will result in the

replacement of aged facilities with natural gas plants and the introduction of natural gas vehicles, which

will in turn lead to an increase in natural gas use. Also, if abnormal weather, such as frequent typhoons

or droughts, continues, immediate action to fight global warming will be taken.

On the other hand, if Asia becomes region oriented, and if the concerted action against global

warning becomes a burden for Asian economies, global and Asian countermeasures will not be taken.

As a result, the current energy system profile will continue to be the major policy for regional

environmental action, in which case the most important technologies would still be desulfurization and

denitration.

2.3 Technology

One of the merits for using natural gas is its low CO2 emission coefficient, as well as its

convenience of use and high efficiency in power generation. The efficiency of the recent ACC Gas

Turbine achieved approximately 50% (LHV base). Also, natural gas is likely to be used as a fuel for

small scale distributed micro gas turbines and mid to large scale high efficiency (60%) fuel cell

generation.

However, these technologies are still in the hand of advanced countries, so the point for the

role of natural gas is whether these technologies will make it to Asian countries. As for the third driving

force, “technology”, we will focus not only on the “R&D” for advanced technology but also the

“deployment” in Asia with the reduction in costs and the cooperation between developed and

developing countries.

As shown above, the key factor regarding technology is whether these technologies, which can

only be achievable with natural gas, take root.

Two stories

Based on these three key driving forces, we have developed future stories until 2030 based on

the direction these driving forces take. This means that there are eight different possible future stories.

In this report, since we wish to highlight the different potential futures in Asia, we deal with two different

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stories. One is the “Ebb & Flow” case where all three of these driving forces have a negative affect on

the spread of natural gas use in Asia. The other is the opposite world case in which they all work

favorably for the natural gas industry.

Because of the uncertainty of these three driving forces, we believe that both of these stories

are equally probable based on the current situation.

Figure 3 shows a comparison of the two stories, “Ebb & Flow” and “Tsunami”.

• Ebb & Flow– No serious and real concern over security

of supply in relation to the dependency on oil imports from the Middle East.

– Regional environmental problems become tangible, however, no participation of developing countries in taking measures against global warming.

– Technological development and cost reduction concerning gas use progress gradually.

– Demand for gas increases steadily.

– No special drive for the installation of multilateral infrastructure works.

– The conventional system of bilateral supply (PL, LNG) is mainly used.

• Tsunami– Serious concern over the dependency on oil

imports from the Middle East.

– In addition to regional environmental problems, global warming is also brought into focus. Developing countries also work on countermeasures.

– A fair wind blows for technological development concerning the use and development of gas. Cost is also reduced substantially.

– The demand for gas increases sharply from around 2010 onward.

– Multilateral infrastructure further promotes regional gas resource development.

– Advancement of the steps to promote the foreign capital introduction in gas sector.

– Advancement of gas-to-gas competition.

Figure 3: Comparison between two storylines for Asia’s energy future

The following chapters describe these storylines on the perspective of Asia and some of its

representative areas.

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3. Ebb & Flow

3.1 Outline

In the “Ebb & Flow” case, countries in Asia focus on their own economic growth, and, as a

result, oil imports increase, which leads to a rapid increase of oil import dependency on the Middle East.

Energy security concerns arise, but no special actions except for current policies and programs, are

taken. Because of the need to reduce local and regional air pollution, and due to the pursuit of

convenient life styles based on an improvement in living standards, trends, such as a shift from old

forms of power generation to natural gas fired generation and domestic use of natural gas, increase

gradually but only where natural gas is available.

Because of this limited shift toward gas, instead of developing into a broad network with an

extensive area, the natural gas infrastructure adopts limited transmission, such as resource-to-demand

domestic transmission or perhaps bi-lateral pipelines and LNG transportation. This is very similar to the

current Asian gas industry, and even though there is pressure for gas price reductions, a competitive

environment is not established. Technology developments and the use of new natural gas technologies

are not likely to occur because of the lack of attention paid to the natural gas industry. The role of

natural gas is quite limited or only slightly better than today.

As shown above, in the “Ebb & Flow” world, awareness of the use of natural gas exists, but no

firm action, such as overcoming geopolitical issues and large-scale infrastructure, is taken. As a result,

the growth of natural gas is slow. In the power sector, an energy shift from coal to gas increases, but in

the transport sector, oil use grows very rapidly.

The following subsections describe “Ebb & Flow” storylines for major areas until 2030.

3.2 China

At the end of the 20th century, China experienced a sustained high economic growth over 7%

per annum for more than ten years. This high economic growth in China continues until around 2010,

with the increase of special procurements for the Beijing Olympics, followed by a gradual transition to

steady growth. The Olympic Games in 2008 boost the use of natural gas in urban areas. However, the

use of oil increases much more, especially in coastal areas, the demand being supplied by imports

from the Middle East.

With the increase in economic growth and energy consumption, local environmental issues like

air pollution become even more serious on Chongqing, Guiyang, and major cities along the coast. In

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order to overcome local pollution, the use of cleaner fuels is decided as a major policy in the 11th

five-year plan (2006-2010). Most of importantly, the priority of developing and using natural gas is made

public.

There are great expectations for clean coal technology in order to meet local air quality

standards, such as those for NOX and SOX reduction, but the share of coal in the primary energy source

decreases steadily. The construction of coal power plants is finally prohibited because of the amount of

fly ash produced, as well as pollution. In big city areas like Shanghai and others, coal fire power plants

are converted to natural gas fueled Combined Cycle Gas Turbines (CCGT) as a new power source.

In 2007, the “West to East Natural Gas Pipeline” project is in service, as planned, and natural

gas is supplied to major inland areas and Shanghai to support growing demand. Between 2005 and

2008, LNG projects are also started in Fujian Province, Shandong Province, and others areas following

the one in Guangdong Province which supports the energy demand in coastal cities.

In or after 2015, a Sino-Russian (Eastern Siberian) pipeline is put into operation in order to

satisfy demand in northern China, but it does not extend to the Korean Peninsula.

Intensive surveying and exploration is now carried out in China in order to meet natural gas

demand. Several gas field development projects, including offshore projects, in China are implemented

in succession, as well.

3.3 Southeast Asia

This area is, in general, rich in energy resources, and is now an energy exporter. As ASEAN

countries’ energy demand grows, their situation, as an energy supplier, will gradually change.

As oil resources in Indonesia decrease, the country becomes a net importer of oil around 2005,

which causes the country’s energy system to shift toward natural gas and coal use. However, new LNG

export projects in areas such as Tangu come into being.

Malaysia continues to export LNG from Sarawak and Sabah on the island of Borneo, while

expanding gas pipeline imports for use on the Malaysian peninsula. In order to develop LNG and

natural gas pipeline projects, it is decided to promote the introduction of foreign capital as a main policy.

In Thailand, a shift from oil and coal progresses in the electric power sector because promoting

coal becomes difficult. Also, hydropower development in the Mekong River Basin and coal-fired

thermal power plants based on the IPP business scheme face significant opposition from local

residents.

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As a result, cooperation between countries such as Indonesia and Malaysia, and Malaysia and

Thailand, promotes bilateral pipeline projects, such as those in JDA (Joint Development Area between

Thailand and Malaysia) and Natuna (Indonesia) and Malaysia.

3.4 South Asia

Currently, this region's energy system typically relies on resources, such as coal and oil, from

within the area, but numerous natural gas projects are proposed.

Coal is still the major source of energy in power generation and the industrial sector, but in the

coastal areas where access to domestic natural resources is difficultly, latent demand for natural gas

increases further. Because of its coal based energy supply, problems with air pollution and other

environmental problems such as fly ash gradually become tangible. In order to resolve this situation,

the development of domestic gas using foreign investment is now promoted based on the government

strategy called the New Exploration Licensing Policy or NELP.

Even though the standstill of Dabhol LNG Power Project run by Enron, a few of the proposed

LNG projects including renewed Dabhol Project start importing by 2010. However, various natural gas

pipeline projects from the Middle East and Turkmenistan passing through or destined for Pakistan and

Afghanistan have difficulties because of long lasting geopolitical issues in the area.

3.5 Australia

Australia is unique in that it is both an energy exporter and a developed country. The Australian

economy also attains steady growth as Asian economies expand. This will enhance the economic

relationships between Asia and Oceania. Matching the growing demand for natural gas in East Asia,

Australia's LNG exports gradually increase, mainly through expansion in the North West Shelf and the

new joint project, Bayu Undan with East Timor, etc.

As the consumption of coal in Asia increases as a base load of power source, Australia's coal

exports also increase.

Figure 4 shows the overall structure of the “Ebb & Flow” energy story. Each box indicates a

driving force or a incident that will lead Asia to gradually increase natural gas use.

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Continuation of steady and relatively high economic growth (China: 6 - 7%, India: around 5%, Southeast Asia: 4 - 5%).

Integration of regions and economies does not proceed, being not much different from the present situation.

A shift to forms of energy with greater convenience (gas and electric power) at the stage of final consumption. Hence, a demand for gas increases at a rate 1 - 2 points higher than that for total energy.

In regions with pollution, in particular, directives and regulations concerning existing electric power corporations, IPP, and others are enhanced to use natural gas as the fuel for newly constructed power plants.

As a result of this, an additional demand for gas is boosted.

Oil is dominant in uses for transportation, with limited penetration of gas.

No positive public support is rendered for establishing a multilateral infrastructure (each project progresses based on the economics of each individual business).

In South Asia, LNG in India starts up to expand gradually with the center being focused on coastal areas. Large scale PLs do not advance.

As for supply, bilateral arrangements (LNG and PL) advance as in the present situation.

In the residential sector, the use of gas mainly penetrates steadily in urban areas.

An increase in the use of gas in new areas such as MGT, fuel cells, and others is limited.

In the power generation and industry sector, a steady shift from coal and oil to gas goes on.

Improvement in income, living standard associated with economic growth (per capita income will increase about twofold in the coming twenty years, with the average income in Asia reaching 6000 -8000 dollars)

In Southeast Asia, bilateral pipeline projects are gradually advanced to cover gas supply.

Occurrence and enlargement of partial prohibition and limitation of operation of coal -fired power generation in urban suburbs (in particular, old and inefficient power plants).

Competitiveness of gas increases in association with an improvement in the flexibility of gas transactions and a gradual decrease in prices.

The gas industry system in Asia changes little. Changes seen at present (deregulation, liberalization and privatization) and others continues gradually.

In East Asia, the present system with LNG being the main axis continues as is, and supply by means of PL is limited to partial use.

Further increase in the seriousness of pollution problems associated with coal use, problems of air pollution, and acid rain, with the result that governments set about taking countermeasures.

With the background of a steady increase in demand, there is an increase in supply as well.

Oil imports from the Middle East increase substantially, but serious trouble in supply does not occur, resulting in a limited increase in concern over increased dependency on the Middle East.

As the liberalization of the domestic markets of gas and electric power in Asian countries goes on, the purchasing side becomes directed toward the purchase of gas at more competitive prices, but downward pressure on the price only has a gradual effect because not much intensification in “gas-to-gas" competition can be seen.

Technological development and diffusion concerning the use and development of gas advances gradually.

Cost reduction in fields of new uses also advances gradually.

In new uses and development, niche markets are secured, but a large increase is difficult to attain.

Gas is turned into a commodity little by little.

Promotion of domestic production of gas by introducing foreign capital.

In renewables, relatively high cost acts as a bottleneck. Certai n constraints on enlargement.

No special momentum or imperative exists for establishing an infrastructure to link the entire region.

Coal: Use in baseload power source. Consumption increases, while share decreases.

Oil: Dominant in uses for transportation. No big change in share in energy mix.

Gas: A substantial increase in power generation and industrial sector. There is an increase in uses for the residential sector as well. Share also grows.

Renewables also increase both in quantity and in terms of share. However, they contribute little as a whole.

Figure 4: Overall structure of the “Ebb & Flow” case

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4. Tsunami

4.1 Outline

In the “Tsunami” world, advances of regional economies increase both oil imports to Asia and

reliance on the Middle East. Based on the situation, fears for oil supply disruptions become concern as

a severe energy security concern for all countries in Asia. As a result, Asian countries have to shift to

natural gas to enhance energy security.

Global climate change affects the economy in Asia and Oceania, and these regions decide to

take active participation in the second commitment period of the Kyoto Protocol. Thus increases of coal

use become slowed and, by using Kyoto Mechanisms such as the Clean Development Mechanism

(CDM) and the emission trading, advanced technologies, such as high efficiency power generation,

natural gas vehicles, and distributed gas power generation, are aggressively introduced to countries in

Asia.

Increase in natural gas demand first activates the development of domestic transmission

business, and then leads to an expansion of mutual connections of regional networks. Despite active

development of domestic gas exploration, the limited amount of resources results in a movement to

develop massive multilateral infrastructures overcoming geopolitical difficulties in order to utilize

abundant natural gas resources in neighboring areas such as the Middle East, Russia, and Central

Asia.

As a result, natural gas becomes available throughout Asia, and the development of natural

gas grids including LNG trade causes the gas-to-gas competition, gradually turning natural gas into a

commodity.

As shown above, the world of “Tsunami” depicts a world in which an economically united Asia

takes concerted action toward dealing with security concerns caused by an excessive dependence on

oil from a particular region. These security concerns and the action taken to protect the environment on

a local, regional, and global scale make the use of domestic gas a priority, and this action leads to the

development of a multilateral natural gas infrastructure that links local domestic pipelines together

based on mutual trust, and this in turn enhances mutual dependencies.

The following subsections describe “Tsunami” storylines for major areas until 2030.

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4.2 China

With the further advance of motorization, a substantial increase in demand for oil for

transportation is observed. Oil imports to China exceed 100 million tons and dependency on the Middle

East reaches more than 80%.

China seeks and develops closer political relations with the Middle East. But at the same time,

the government moves toward a continued shift to gas from the standpoint of developing domestic

sources and resources in Asia, including Eastern Siberia.

Toward 2008, in order to promote the success of the Olympics, China seeks to enhance its

image as a clean nation. All of its existing heating plants and power plants are converted to natural gas

fuled plants. An enormous number of vehicles, initially only buses in Beijing but eventually all

commercial vehicles, are asked to convert to natural gas power.

Around 2010, abnormal weather and drought in grain crop areas in China cause a great failure

in agriculture. Global warming now becomes a political issue, and, in the 12th five-year plan

(2011-2015), the necessity of addressing global warming is advocated. As part of such efforts, the

promotion of gas use for power generation and industry becomes the focus of energy policy issues.

Additional LNG projects are implemented from 2010 onward to supply major coastal cities. The

Sino-Russian pipeline has expanded in northern China, and supply now extends to South Korea, as

well. Further extension to western Japan also comes into view. The Sakhalin pipeline for Japan

continues as a successful project, and now expands its operations to China.

An offshore Chinese pipeline and pipelines connecting southern China LNG receiving

terminals now form an East Asian corridor pipeline. Natural gas trading points are formed in Shanghai,

Guangdong, Xiamen, Beijing, Inchon, Japan, Sakhalin, and some other major cities that become hubs

for the Asian natural gas price index. Gas use spreads steadily in areas along pipelines.

The completion of wide-area pipeline networks accelerates gas field development in Sakhalin,

Eastern Siberia, and off the coast of China. The introduction of foreign capital also progresses with the

addition of the development of gas fields.

4.3 Southeast Asia

Although the economy continues its upward trend, in order to maintain competitiveness to

other regions, the incentive for inter-regional integration in ASEAN countries has gained momentum.

As with China, the expansion of oil imports and increase in dependency on the Middle East progresses

steadily. Even resource rich countries, first Indonesia, then Malaysia, become net oil-importers.

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Consequently, due to increasing concern over dependency on the Middle East, the utilization of

intra-regional resources is given greater importance.

On the one hand, regional environmental problems in countries of the region become more

serious with the use of conventional energy, and countries face growing pressure from residents

focusing on environmental problems. On the other hand, abnormally high temperatures and abnormal

weather problems in Southeast Asia, China, and India become the focus of attention. Around 2015,

awareness of the need to address the issue of global warming increases rapidly throughout Southeast

Asia.

Heads of ASEAN nations decide on the full-scale promotion of the Trans ASEAN Gas Pipeline

(TAGP) and Trans ASEAN Power Grid (TAPG) projects as regional networks to solve the above

mentioned environmental issues. The TAGP network within ASEAN is now in operation as a wide-area

network linking the Philippines, Vietnam, and other countries for complete coverage of ASEAN nations.

Gas transactions are activated in major consumption and production areas in each country.

For electric power networks, as well, generated power based on the available resources in

each country (e.g., hydropower, gas, coal, new energy) is connected to the networks, gradually forming

TAPG.

With vigorous demand for natural gas in East Asia, LNG exports in ASEAN also progress. The

completion of a pipeline network within ASEAN enhances regional gas resource development by

introducing foreign capital. In addition to large-scale gas fields, small and medium-size gas fields also

contribute significantly to expanding production capacity.

4.4 South Asia

The development of natural gas use in South Asia depends heavily on the ability to overcome

geopolitical issues related to importing natural gas from the Middle East. Once these issues are

overcome, tremendous potential demand will develop in the region for natural gas. While East Asia and

Southeast Asia enhance intra-regional cooperation, South Asia will strengthen cooperation with the

Middle East and Central Asia because they are in the same market sphere. The expansion of gas use

will become important as a means of diversifying energy sources, but South Asia will continue to rely

heavily on the Middle East.

Around 2010, drought and abnormal weather occur in South Asia as well, and agriculture

suffers great damage. In addition to regional environmental problems that become increasingly serious,

the need to take countermeasures against global warming also becomes urgent in this region.

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In addition to advanced uses of coal, the energy saving promotion, and renewable energy, the

closing down of inefficient coal-fired power plants and a shift to gas are thoroughly promoted,

particularly in heavily populated areas.

Natural gas exploration is promoted based on this and, later on, the New Exploration Licensing

Policy (NELP). As Afghanistan undergoes reconstruction, a natural gas pipeline import project

becomes politically important. With support from the global community for stabilizing the area, pipeline

projects from central Asia and the Middle East become a reality in the latter part of the 2010s.

4.5 Australia

Noticing a strengthening of intra-regional cooperation in the economies and energy industries

in various regions throughout Asia, Australia searches for a way of enhancing its presence in Asia.

With a significant increase in natural gas demand in East Asia, the volume of LNG exports

increases, but Australia now faces competition in the continental Asian natural gas market with pipeline

gas and other LNG projects, and this competition gradually intensifies. Due to gas-to-gas competition,

a strategy for responding to competition is advised in order to deal with flexible transactions,

competitive pricing, cost reductions, and so on.

The low demand for coal in Asia affects coal exports, including exports from Australia. In order

to make up the loss, efforts are initiated together with consuming countries to develop and make best

use of the clean coal technology.

Figure 5 shows the overall structure of the “Tsunami” story. Each box indicates a driving force

or a incident that lead Asia to gradually increase natural gas use.

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International energy businesses (oil majors and others) also participate positively in the establishment of infrastructure, with their by strong capital and technological power.

In Southeast Asia, the ASEAN grid is completed by the advancement of bilateral links, functioning as infrastructure for regional supply.

As a result of the establishment and diversification of gas supply networks, “gas-t o-gas”competition is activated.

In addition to establishing conventional bilateral PLs, LNG receiving terminals and domestic PLs, the establishment of multilateral PLs advances, thereby forming major "hubs" of the import, receiving and transactions of natural gas in various parts of Asia.

With intensified competition, gas prices decrease steadily, thus strengthening competitiveness against other energy sources.

In East Asia, PLs in which China, South Korea (North Korea), and Japan are consuming countries, and Russia and Central Asia are supplying countries are started at first from relations between China and Russia, and between Japan and Russia, to be developed into multilateral PLs.

The trend to use natural gas resources within the region increases substantially.

Emphasis is placed on establishing a multilateral infrastructure, thus public financial support enlarge.

In South Asia, large-scale PLs from the Middle East or Central Asia are completed and put into operation.

The establishment of large-scale multilateral PLs greatly promote upstream investment in gas field close to the infrastructure.

From around 2010 onward, the movement of promoting the establishment of multilateral, wide-area PLs is started and strengthened.

In 20XX, large-scale supply disruption occurs in the Middle East. Owing to the sharp increase in crude oil prices and supply trouble in Asia as well, concern over the dependency on oil from the Middle East intensifies rapidly.

From around 20XX onward, serious damage occurs in developing countries due to the effects of global warming (e.g., abnormal weather, desertification, lower agricultural production ).

In the course of the flow of steady demands and market liberalization, the LNG market also grows in East Asia. Besides, under the growth of PL supply and gas market liberalization, gas market become increasingly competitive and contestable .On the West Coast of North

America, LNG receiving terminals are put into operation, strengthening relation with the LNG market in Asia. Making a contribution to competitive prices and an increase in the of flexibility transactions.

Demands for gas in major sectors such as power generation, industry, residential, and others are further boosted. A demand for gas in new uses also being stimulated.

Dependency on oil imports (dependency on the Middle East) greatly increases. Increasing concern over security.

A fair wind for technological development and diffusion concerning the use and development of gas.

A decrease in cost in new fields of use greatly advances.

The efficiency of existing technologies improves, with cost reduction also promoted.

Coal: Seriously affected as a result of promoting a shift to gas. Share decreases considerably.

Oil: Maintains its major status in uses for transportation. But is partially replaced by other fuels. Share is declining.

Gas: Replacing coal and oil to obtain a large share in sectors of power generation, Industry and residential. Winner!

Renewables also grow substantially. Share increases as distributed and local energy.

Gas becomes a commodity. Volatility of gas prices increases.

•Issues of the gas industry:•Difficulty in making investments.•Necessity of decision hedging, against risk.•Gas supply security.

To meet the increasing demands for gas, promotion of the development of gas (introduction of foreign capital) accelerates further.

Regional environmental problems further become more serious as energy consumption grows in various parts of Asia.

Economic growth accelerates partly due to (expectations of) integration effects, with demands for energy increasing steadily.

Global economic competition intensifies, and the momentum of promoting regional and economic integration in Asia also increases.

Developed and developing countries discuss emission control measures at a level that is not unrealistic and acceptable by developing countries side, and major developing countries in Asia start working on countermeasures against global warming.

Developed countries continue efforts for the initial commitment period of the Kyoto Protocol, but the importance of the participation of developing countries and the recognition of the necessity of support increase.

In association with increases in income levels, the environmental awareness of citizens in Asia is also heightened, and the addressing of environmental problems becomes important political issues.

Figure 5: Overall structure of the “Tsunami” case

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5. BUSINESS IMPLICATIONS

Common challenges shared by the two storylines

• Necessity to increase supply capacity to cope with increasing gas demand, and to secure

investments therefor.

• Necessity to ensure the security of intra-regional gas supply in accordance with the

increasingly important role of gas.

Ebb & Flow

• Due to the gradual intensification of gas price competitiveness and industrial restructuring,

demand for rapid restructuring may arise after the period covered in the analysis (or toward

the latter part of that period).

• Likewise, after the period covered in the analysis (or toward the latter part of that period),

an urgent call may be made for environmental measures such as countermeasures against

global warming, as well as for a response thereto.

Tsunami

• Intensification of gas-to-gas competition turns gas into a commodity. Price volatility also

increases sharply.

• In such a new business environment, hedging against risk, securing investments, and

other countries become increasingly important.

Report of Special Project 1-A “Catalysing Asia's Energy...

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