Proceedings - Expert Group on Clean Fossil Energy - Asia-Pacific ...

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Proceedings - Expert Group on Clean Fossil Energy - Asia-Pacific ...

Coal in Sustainable Development in the 21st Century

PROCEEDINGS OF THE

JOINT 8TH APEC COAL FLOW SEMINAR

AND THE

9TH APEC CLEAN FOSSIL ENERGY

TECHNICAL SEMINAR

Hotel Istana, Kuala Lumpur, Malaysia

Monday 4 March & Tuesday 5 March 2002

ASIA-PACIFIC ECONOMIC COOPERATION

ENERGY WORKING GROUP

CLEAN FOSSIL ENERGY EXPERTS’ GROUP

ORGANISED UNDER THE DIRECTION OF THE

APEC EXPERT GROUP ON CLEAN FOSSIL ENERGY (EGCFE)

PROJECT STEERING COMMITTEE

AUSTRALIA: Department of Industry, Tourism and Resources (ITR)

CANADA: Department of Natural Resources

JAPAN: Ministry of Economy, Trade and Industry (METI)

KOREA: Korea Institute of Energy Research (KIER)

MALAYSIA: Ministry of Energy, Communications and Multimedia (MECM)

PR CHINA: State Power Corporation of China

USA: Department of Energy (DOE)

SPONSORED BY:

JAPAN: New Energy and Industrial Technology Development Organization (NEDO)

The Japanese Committee for Pacific Coal Flow (JAPAC)

MALAYSIA: Ministry of Energy, Communications and Multimedia (MECM)

TNB Fuel Services Sdn. Bhd

USA: Department of Energy (DOE)


CONTENTS

OPENING REMARKS

Official Welcome & Keynote Address: Malaysian Coal Resources: Opportunities

and Challenges

The Honourable Datuk Amar Leo Moggie, Minister

Ministry of Energy, Communications and Multimedia (MECM), Malaysia

Official Welcome: Australia/Japan/USA

Australia: HE Peter Varghese

Australian High Commissioner to Malaysia

Japan:

USA:

Mr Hiroshi Hirota

Deputy Director-General

Agency of Natrual Resources and Energy (ANRE)

Ministry of Economy, Trade and Industry (METI), Japan

Mr Scott M Smouse, Senior Management and Technical Advisor

National Energy Technology Laboratory

Department of Energy (DOE), USA

SESSION 1:

COAL FLOW

PACIFIC COAL FLOW AND ENERGY SECURITY

Chair: Mr Scott M Smouse, Senior Management and Technical Advisor

National Energy Technology Laboratory

Department of Energy (DOE), USA

The Current Situation of Energy Supply and Demand in Japan

Mr Kazuo Sugiyama, Chairman

The Japanese Committee for Pacific Coal Flow (JAPAC); and

Former President, Electric Power Development Co., Ltd. (EPDC), Japan

The World Coal Market: Prospects to 2010

Ms Jane Melanie, Senior Economist, International Energy Program

Australian Bureau of Agricultural and Resource Economics (ABARE)

Australia

Coal Demand and Supply Outlook

Mr Bai Ran, Director General, Department of International Cooperation

China National Coal Association, PR China


SESSION 2:

COAL IN OPTIMUM ENERGY MIX (SECURITY

AND ENVIRONMENT)

Chair: Mr John Karas, Manager, Coal Industries Section

Department of Industry, Tourism and Resources (ITR), Australia

New Role for Coal and CCTs in Energy Security in APEC

Dr Charles Johnson, Energy Consultant

Asian Energy Strategies, USA

Power Industries in Korea

Dr Chang-Seob Kim, Chief of Climate Change Policy Team

Korea Energy Management Corporation, Korea

Energy Development Plans

Mr Shih-Ming Chuang, Division Manager, Energy Commission

Ministry of Economic Affairs (MOEA), Chinese Taipei

SESSION 3:

COAL AND GLOBAL ENVIRONMENT

Chair: Dr Frank M Mourits, Manager

Climate Change Technologies Initiative

Office of Energy Research and Development, Natural Resources Canada

Impact of Kyoto Mechanism on Coal

Dr Yoshiki Ogawa, General Manager

The Second Department of Research

The Institute of Energy Economics, Japan

Coal in Sustainable Society

Dr Louis Wibberley, Manager Environment & Sustainability

BHP Billiton, Australia

CO 2 Emission and CDM Projects

Ms Lucila Q Maralit, OIC-Assistant Director

Energy Resource Development Bureau

Department of Energy (DOE), Philippines

Day 2: Opening Remarks

Mr Hiroshi Yoshida, Executive Director

New Energy and Industrial Technology Development Organization (NEDO),

Japan

SESSION 4:

THE ROLE OF COAL IN SOUTH EAST ASIA

Chair: Mr Haji Abdul Hadi Deros, Vice President (Generation)

Tenaga Nasional Berhad, Malaysia

Export and Domestic Use

Dr Boni Siahaan, Deputy Assistant for Mining and Energy Business

Ministry of State Owned Enterprises

Indonesia


Coal and Natural Gas in the Future

Mr Tran Van My, Deputy Manager General

Division for International Cooperation & Development Project

Institute of Mining Science and Technology (IMSAT), VINACOAL Vietnam

Move from Gas to Coal: Energy Security Issues

Ms Yap Siew Hong, Director of Energy Section

Economic Planning Unit (EPU), Malaysia

SESSION 5:

COAL TECHNOLOGY

ENVIRONMENTAL TECHNOLOGIES IN COAL-

FIRED POWER PLANT

Chair: Dr Boni Siahaan, Deputy Assistant for Mining and Energy Business

Ministry of State Owned Enterprises

Indonesia

Pollution (SO x , NO x , Particles) Treatment

Mr Shigehito Takamoto, General Manager

Environmental Research Department, Kure Research Laboratory

Babcock-Hitachi K.K, Japan

Trends in Coal Combustion Products (CCP) Utilization in North America

Mr Jim MacLean, President

Dominion Ash, Canada

Clean Coal in a Competitive Electricity Market

Mr Lindsay Juniper, Managing Director

Ultra-Systems Technology, Australia

SESSION 6: PRESENT SITUATION AND TREND OF HIGH

EFFICIENCY COAL COMBUSTION

TECHNOLOGIES

Chair: Mr Hiroaki Ichinose, Deputy Director

Coal Industry Division, ANRE

Ministry of Economy, Trade and Industry (METI) Japan

Feasibility of New Coal Fueled Power Plants in the US

Ms Natalie Rolph, Chief Economist

Black & Veatch - Energy Services ong>Groupong>, USA

IGFC (Eagle Project)

Mr Eiki Suzuki, Assistant Manager, Coal Gasification ong>Groupong>

Wakamatsu Coal Utilization Research Center

Electric Power Development Co., Ltd. (EPDC) Japan


Supercritical PF

Mr Zhao Zongrang, Senior Engineer

Thermal Power Research Institute, PR China

(paper jointly authored by: Mr Li Guanghua, Director of Section

State Power Corporation of China, PR China)

SESSION 7: EMERGING TECHNOLOGIES TO REDUCING GHG

EMISSIONS

Chair: Dr Sung-Chul Shin, Senior Advisor

Korea Institute of Energy Research (KIER) Korea

Techno-economic Assessments by the Zero Emission Coal Alliance

Dr Frank M Mourits, Manager, Climate Change Technologies Initiative

Office of Energy Research and Development

Natural Resources Canada

Clean Coal Technology Initiative

Mr Scott M Smouse, Senior Management and Technical Advisor

National Energy Technology Laboratory

Department of Energy (DOE), USA

Demo Plant of CO 2 Separation and Conversion

Dr Jae-Goo Shim, Senior Member of Technical Staff, KEPRI

Korea Electric Power Corporation (KEPCO) Korea

SESSION 8:

SUMMARY

Dr Charles Johnson, Energy Consultant, Asian Energy Strategies, USA

AGENDA

PROFILES OF SPEAKERS

PARTICIPANTS’ LIST


OPENING SESSION:

Chair: Mr Scott Smouse

Senior Management and Technical Advisory

National Energy Technology Laboratory

Department of Energy (DOE)

USA


Official Welcome

& Keynote Address:

MALAYSIAN COAL

RESOURCES – OPPORTUNITIES

AND CHALLENGES

The Honourable Datuk Amar Leo Moggie

Minister, Ministry of Energy, Communications and

Multimedia (MECM)

Malaysia


KEYNOTE ADDRESS BY DATUK AMAR LEO MOGGIE

MINISTER OF ENERGY, COMMUNICATIONS AND MULTIMEDIA,

MALAYSIA

AT THE 8 TH APEC COAL FLOW SEMINAR/9 TH APEC CLEAN FOSSIL

ENERGY TECHNICAL SEMINAR/4 TH APEC COAL TRADE, INVESTMENT,

LIBERALISATION AND FACILITATION WORKSHOP

4 MARCH, 2002

-------------------------------------------------------------

It gives me great pleasure to be here with you today and I would like

to thank the organizers of these series of APEC Seminars and Workshop on

Coal, for inviting me to deliver this keynote address. I note that for the first

time the 8 th APEC Coal Flow Seminar, the 9 th APEC Clean Fossil Energy

Technical Seminar and the 4 th APEC Trade, Investment, Liberalization and

Facilitation Workshop, are being held together. We are delighted that Kuala

Lumpur has been given the honor to host these events. On behalf of the

Ministry of Energy, Communications and Multimedia I wish a warm welcome

to all participants and “Selamat Datang” to our overseas participants.

Today, as most of our economies are recovering from the financial and

economic crisis, we can expect resurgence in energy demand. To meet this

demand, energy supply infrastructure will need to be continuously developed

and being very capital intensive, it will impose tremendous pressure on the

natural resources, particularly for developing economies. At the same time,

we are aware that the current patterns of growth, resource use and

environmental degradation cannot extend indefinitely into the future. Also,

we realize that in terms of energy use and supply, we need to encourage the

most efficient utilization of resources.

This concern had led to the conclusion, ten years ago in 1992, of

Agenda 21, the landmark agreement on key issues and goals of sustainable

development. In the later part of this year, heads of governments,

international organizations, NGOs and other stakeholders will again be

meeting to review the progress in the implementation of this Agenda.

Against this background, the selection of the theme of this week’s

conference, “Coal in Sustainable Development in the 21 st Century” is timely.

Coal, being the most abundant energy resource and also one of the

cheapest, will have to feature markedly in meeting the goals of sustainable

development.

It is said that as many as 2 billion people or almost one third of the

world’s population have no access to modern energy services. Unfortunately,

the majority of this 2 billion people live in the Asia-Pacific region. Since

energy is crucial in achieving the goals of sustainable development, greater


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efforts need to be taken to implement policies, strategies and action

programs that will ensure these 2 billion people have access to adequate and

affordable energy supply. At the same time, the goals of sustainable

development also require that programs to provide greater access of energy

supply be implemented with a minimum compromise on environmental

quality. This remains as one of the greatest challenges facing us in this new

millennium.

TOWARDS A MORE SUSTAINABLE ENERGY MIX

Ladies and Gentlemen,

Malaysia is fortunate to have large domestic energy resources and an

established energy infrastructure that supply affordable and reliable energy

to a wide variety of consumers, from industry to households. This has been a

key factor in the nation's robust economic growth of the last three decades.

Malaysia’s energy policy is designed to promote and support the

growth and development of its economy in a sustainable manner. Even

during the economic crises of 1997, the thrust of Malaysia’s energy policies

continued to focus on ensuring adequate, secure and cost-effective supply

and utilizing the energy resources efficiently, while minimizing its negative

impacts on the environment.

A predominant feature of the Malaysian energy supply mix until early

1980s was an extremely high dependence on oil. Realizing this was not

sustainable, the Government formulated a National Depletion Policy in 1980

aimed at extending the life of oil reserves by establishing appropriate oil

production levels, relative to available reserves. This was complemented a

year later by the “Four-Fuel Strategy” aimed at ensuring reliability and

security of supply, with a supply mix of oil, gas, hydropower and coal in

energy use. As much as possible, local resources of these fuels were used to

enhance security of supply. In particular, the electricity sector emphasized

the installation of non-oil capacity, while in the cement industry, the

conversion of all major cement kilns to dual fuel fired (oil and coal) systems

was carried out.

With its discovery in 1983, gas began to make significant contribution

primarily in electricity generation, while coal, which was entirely imported

then was consumed mainly in the cement and steel industries. In 1985, oil

accounted for 61.9 per cent of total primary energy supply, gas 18.1 per

cent, hydro 2.9 per cent and coal 2.8 per cent. The success of the

diversification policy has reduced the share of crude oil and petroleum

products in the total energy supply, accounting for 53.1 per cent in 2000.

The share of natural gas increased significantly to 37.1 percent, coal and

coke at 5.4 per cent and hydro at 4.4 per cent. Coal and coke grew as a

result of increased usage in foundries and cement plants.


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The diversification strategy has seen greatest success in the electricity

generation sector. The share of oil in electric power generation in 1980 was

87.2 percent, hydropower 12.5 per cent and gas 0.3 per cent. By 2000, the

share of oil in the electric power generation mix declined sharply to a mere 5

per cent, while gas increased significantly to 75 per cent, coal and coke at 10

per cent and hydro power at 10 per cent. The use of coal as an energy

source in electricity generation in Malaysia was aimed at ensuring system

security and reliability.

The economy’s overall energy mix is continuously being reviewed to

ensure the long-term reliability and security of energy supply. Concerted

efforts are being undertaken to ensure the sustainable development of

energy resources, both depletable and renewable, in meeting the energy

demand of the economy. The contribution of crude oil and petroleum

products is anticipated to decline further to 50.8 per cent by year 2005, while

that of natural gas and coal is expected to increase to 39.9 per cent and 5.9

per cent, respectively. At the same time, efforts will be intensified to

encourage the utilization of renewable resources for the generation of

energy. In this respect, the fuel diversification policy, which comprises oil,

gas, hydro and coal, has been extended to include renewable energy

resources as the fifth fuel.

ROLE OF COAL IN ENERGY MIX

Ladies and Gentlemen

Coal is mainly consumed by power generation plants and cement

manufacturing industries, accounting for 99 per cent of the total coal

demand. Production though small, grew from 65,000 tonnes in 1991 to

383,000 tonnes in 2000. Most of the coal produced locally was utilized by the

Sejingkat power station in Sarawak with a capacity of 100 megawatts (MW).

The total coal requirement of this plant is 300,000 tonnes per annum.

Another coal-fired power plant completed was the Phase 3, Kapar power

station, with an additional capacity of 1,000 MW. This plant, which utilizes

imported coal, will require 2.5 million tonnes per annum.

The electricity industry will play a leading role in increasing utilization of

coal for power generation in the coming years, up to 2010. Hence, coal

demand for electricity generation in the economy is projected to increase

sharply, from an estimated 6.03 million tonnes in 2000 to between 19 to 20

million tonnes per annum by 2010. This is due to the commissioning of new

coal-fired electricity generating plants, which will account for 60 per cent of

the additional planting up capacity being planned. Up to 2005, 3,800 MW or

43 per cent of new capacity will be coal-fired. Hence, coal will contribute a

significant 30.3 per cent to the total fuel mix in electricity generation in

2005, while that of gas will decline to 61 per cent. A more sustainable fuel

mix for Malaysia in the longer term will see a greater percentage of coal

utilization of between 40-45 percent while that of gas at not more than 50

per cent.


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Coal is also used by the cement industry and the iron and steel

industry. There are seven integrated cement plants in Peninsular Malaysia

and one clinker plant in Sarawak. The consumption of coal by the cement

industry in 2000 was 1.83 million tonnes and expected to increase to 2.13

million tonnes per annum by the year 2005. This is due to the higher

production from existing plants in response to the greater demand

accompanying the nation’s economic recovery.

COAL RESOURCES AND ITS POTENTIALS

Coal resources in Malaysia are found mostly in East Malaysia, in the

states of Sarawak and Sabah. In 2000, the total reserves of coal was

estimated at 1,711.4 million tonnes, of which 275 million tonnes are

classified as measured resources, 347 million tonnes as indicated and

another 1,090 million tonnes as inferred. About 80 per cent of the reserves

are in Sarawak, 19 per cent in Sabah and only 1 per cent in Peninsular

Malaysia.

The coal deposits are of various qualities ranging from lignite to

anthracite with bituminous to sub-bituminous coal forming the bulk.

Unfortunately, most of these known coal areas are located far inland where

infrastructure is poor.

Commercial production of coal began in 1991 and by 2000 there were

6 mines in operation. The present coal production in Sarawak comes from

the Merit-Pila Coal Field, which produced a total of 291,112 tonnes in 1999

and expected to increase to 600,000 by this year; underground mine at

Silantek, producing 15,191 tonnes beginning in 1999; and the Abok Coal

field, producing 2,200 tonnes.

The Merit-Pila Coal Field in Sarawak, which is one of the main sources

of coal supply in the economy, has coal characterized as having moderate

ash content and moisture, very low sulphur and gross calorific values of

about 5000 to 6000. This area’s estimated reserve is about 385 million

tonnes of which 10% may be mined by open cast method.

Another major field is the Mukah-Balingan coalfield, with a reserve at

about 270 million tonnes. The coal is of lignite with high moisture, low

sulphur, low to moderate ash content and a gross calorific value of about

5000 to 5500 per kg. Due to its high moisture content and low calorific value,

the coal from this area is best suited for mine-mouth power plants and for

coal briquettes.

The Silantek coal field contains reserve of 60 million tonnes with coal

type ranging from bituminous to anthracite and semi-anthracite having low

to medium volatiles, low ash, very low sulphur and a high gross calorific

value of about 7000 to 8000 per kg. Some of the coal from this area has

good coking properties.


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The Bintulu coalfield is estimated to have a reserve at 20 million

tonnes of low ash and a high gross calorific value of 7000 to 7500 per kg.

Due to its high heating value and close proximity to a deep-sea port, this

coalfield offers great potential for further development.

In addition to the ones mentioned earlier, coal is known to exist in

other parts of the remote interior of Sarawak. But to date, no attempt has

been made to assess the coal potential of these areas in detail.

In the state of Sabah, coal is known to occur at several places,

including the Maliau and Malibau basins in south-central Sabah and the

Silimpopon and Labuan areas. Maliau coalfield has shown great potential,

having good quality coal and an inferred reserve of 215 million tonnes.

However, this area has been gazetted as Maliau Basin Conservation Area in

1998 by the Sabah State Government. Malibau coalfields have a reserve of

26 million tonnes and Silimpopon 14 million tonnes with potential for

underground mining.

Generally, the coal reserves in Malaysia have heat values ranging

between 5,000 to 7,000 kcal/kg, with low ash and sulphur levels. In view of

the high demand for coal in electricity generation and cement manufacture,

exploration and assessment of coal resources will need to be stepped up with

greater participation from the private sector, particularly in Sabah and

Sarawak. However, Malaysia will continue to be dependent on imports to

meet its coal requirement. Currently, about 90 per cent of the economy’s

coal requirements are being met by imports, mainly from Australia,

Indonesia, China and South Africa. Coal imports are expected to increase

further to 95 per cent by the year 2010.

CHALLENGES FACING COAL UTILISATION

Ladies and Gentlemen,

Because of its abundance and stable price, coal has been and will

continue to be an essential component of long-term sustainable economic

development, not only in the Asia Pacific region but also the world.

Nevertheless, its wider utilization faces several major challenges.

Locally, although Malaysia’s coal resource is substantial and sufficient

to meet its requirement, a major constraint is the high development cost as

coal deposits are located in the interior areas without proper infrastructure.

The development of infrastructure to transport coal is costly and most of the

coalfields require underground mining, which is more costly compared to

surface mining. In addition, the local coal industry faces stiff competition

from other economies with bigger reserves and more established coal

industry.


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With the implementation of the National Mineral Policy, the private

sector will be encouraged to play a key role in the development of coal

resources in the economy, through greater involvement in exploration,

development and production activities. They will be encouraged to take

advantage of new technologies that increase productivity. The most

promising include improvements in underground mining methods, the use of

larger equipment in surface mining operations, and computerization of the

administrative and mine maintenance activities.

Globally, the energy industry is undergoing a transformation driven by

changes such as deregulation of electricity supply industry, more stringent

environmental standards and regulations, climate change concerns, and

other market forces. All these developments present a variety of challenges

and opportunities to the coal industry.

The Kyoto Protocol implications on Climate Change will have profound

impacts on the future of the coal industry and represents a major challenge

facing the coal industry, in particular the power sector. In 1997, it was

reported that CO 2 emissions from the energy sector had exceeded the goal

established at Kyoto by 16%. By about 2010, it has been estimated that

carbon emissions could exceed the goal by more than 35%. There is fear that

technological development and market mechanisms required to meet this

challenge may not be fast enough.

For the region's economic growth and energy security, the coal

industry must respond to the environment and greenhouse challenges. The

environmental problems associated with coal must be closely examined to

find new ways to address these problems. We are pleased to learn of the

technological advances achieved in making coal a much cleaner fuel today. In

particular, significant increases in thermal efficiency and reductions in

sulphur and nitrogen oxides and particulate emissions. With the right

technology, the process of coal extraction, movement and more efficient

combustion system, will help to reduce the environmental concerns

associated with the use of fossil fuel for producing electricity and

transportation fuels.

Malaysia remains committed to the goals of sustainable development

and measures will be taken to ensure that the production and utilization of

coal will meet environmental standards. Clean-coal technology, which will

include among others, electrostatic precipitators and flue gas desulphurization

for emission control, will be utilized in the new plants to

ensure environmental standards are met.

Developed economies will need to lead the way in addressing global

environmental problems such as greenhouse. At the same time, the transfer

to developing economies of cost effective measures to address environmental

impacts through international cooperation is imperative.


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Community attitudes to coal use is another major challenge facing the

industry and this, more often than not, is founded on their general lack of

knowledge and understanding that coal can be used cleanly and efficiently.

The negative image of coal must be addressed to gain wider community

acceptance to its use. This is of special importance to Malaysia as more and

more power plants will be coal-fired. I’m pleased to note that the next few

day’s deliberations will also touch on developing mechanisms to address the

coal's poor image.

In this respect, the APEC Coal seminar and workshop will be an

important forum to contribute, learn and exchange ideas and experiences on

sustainable development of energy resources, namely coal. I welcome the

broad range of topics to be deliberated upon over the next 5 days aimed at

improving regional understanding and addressing issues and challenges

facing development, trade, and investment within the coal and coal-based

energy industries in the APEC region as a whole.

Finally, I wish you every success with these series of APEC Coal

Seminar and Workshop.

Thank you.


Official Welcome:

AUSTRALIA, JAPAN

& USA

His Excellency Peter Varghese

Australian High Commissioner

Malaysia

Mr Hiroshi Hirota

Deputy Director

Coal & Mineral Resources Policy

Ministry of Economy, Trade and Industry (METI)

Japan

Mr Scott Smouse

Senior Management and Technical Advisory

National Energy Technology Laboratory

Department of Energy (DOE)

USA


APEC Coal in Sustainable Development in the 21 st Century

4 to 8 March 2002 – Kuala Lumpur, Malaysia

OPENING REMARKS

HE Peter Varghese

Australian High Commissioner to Malaysia

Distinguished guests, ladies and gentlemen.

It is a great honour to be invited to welcome participants to this important APEC energy

forum.

Looking at the program, the speakers and audience I can see that you are in for a

stimulating and, I hope, rewarding week.

The theme for this conference, coal in Sustainable Development in the 21 st Century, is

one that looks to the future. It recognizes the key role that coal will play in meeting

expanding energy needs. It also recognizes the equal importance of the environmental

and social dimensions.

The 21 st Century holds the promise of high living standards for all countries.

Development will put greater pressures on the environment, but governments and

communities will also place pressure on industry to protect the environment, On the

energy front this requires cleaner, more reliable and more abundant energy. We can also

expect ongoing pressure to reduce energy costs.

The energy sector, particularly coal, certainly has some challenges ahead.

Coal in Sustainable development in the 21 st Century covers a lot of ground. It is perhaps

not surprising that the APEC ong>Expertong>s’ ong>Groupong> on Clean Fossil Energy has, for the first

time, brought together three of its regional forums to cover this topic.

The APEC Clean Fossil Energy Technical Seminar brings together people and

approaches with a technical and technology transfer focus. This is the ninth seminar in

this series. A seminar early in the series was held in Malaysia.

The APEC Coal Flow Seminar brings a focus and expertise based on trade and

investment flows and wider policy and regulatory issues. This is the eighth workshop in

this series.

The 4 th APEC Coal Trade and Investment Liberalisation and Facilitation – TILF for short

– Workshop has been designed to address the specific energy challenges faced by the

host economy.


The combined forum brings together a wise range of expertise, covering all fields, from

across APEC. It provides the basis for a multi-disciplined approach to address the

economic, environmental and social challenges facing coal in the 21 st Century.

The forum this week will address issues from the region-wide perspective and apply them

to the particular circumstances of Malaysia.

And it comes at what I consider is a very opportune time.

Globally it has the potential to feed into the World Summit on Sustainable Development

in September in Johannesburg, South Africa.

For Malaysia, it comes at an opportune time. Malaysia is relatively new to coal, having

only recently decided to diversify into coal for power generation.

Whilst many of us are dealing with the challenges associated with the historical use of

coal, Malaysia can plan its energy future with a clean slate, literally and figuratively. It

has the opportunity to learn from others’ mistakes and successes, and to adopt clean coal

technologies and practices that reflect its future requirements for clean and efficient

energy.

Australia welcomes the opportunity work with Malaysia to build our common knowledge

and understanding on the clean use of coal. Our cooperation has already included

workshops on clean coal technology and coal utilization run by Australia in Malaysia and

participation in technical and power sector management courses run in Australia.

I anticipate that this conference will provide further valuable support to Malaysia from

economies throughout the region.

But this is not just a one way process. As with other APEC activities, this week is about

mutually beneficial cooperation between economies.

Just as Malaysia is learning from this, we also have a lot to gain by looking at the way

Malaysia is moving ahead. We can all learn from the solutions that Malaysia is putting

in place to meet its energy challenges in the 21 st century. The Program for this week,

including the visits to modern coal power stations on Wednesday, will provide plenty of

opportunities to share valuable experiences.

On behalf of the Australian government, I would like to thank Malaysia for hosting this

event. I extend my thanks and congratulations to all the organisers and sponsors from

Malaysia and other economies, and to the APEC ong>Expertong>s’ ong>Groupong> on Clean fossil Energy

for putting this excellent forum together.


Official Welcome – Monday 4 March

Hiroshi Hirota

Deputy Director-General of Coal and Mineral Resources Policy,

Ministry of Economy, Trade and Industry (METI), JAPAN

On behalf of the Japanese Government, I would like to express my heartfelt gratitude

to everyone attending today, and to all the guest speakers who have come from many

economies including APEC members to take part; furthermore to APEC, the EGCFE

Secretariat and everyone from the Malaysian Government for their unstinting efforts in

holding the Coal Flow Seminar, the Clean Fossil Energy Technical Seminar and the

Coal TILF Workshop.

In June of last year, discussions were held in our economy on future energy security,

and a report was compiled. In it, coal is appraised as a low-risk resource in terms of

security compared to other energies such as oil, by virtue of its distribution throughout

the world and the comparative abundance of its reserves. From the standpoint of

maintaining international price negotiating strength in respect to fossil energies as well,

it was considered to be a valid option in ensuring energy security. Furthermore, in July

of last year, the report, "Report on Energy Policy for the Future" from the Advisory

Committee for National Resources and Energy, was presented to the Minister of

Economy, Trade and Industry, outlining the long-term energy supply and demand

outlook until 2010.The report indicates that coal will continue to account for about 19%

of primary energy supply in future, and expectations will continue to be placed in it as a

major energy source.

Nevertheless, while coal demand within the region is expected to increase about 40%

in 2010 compared to 1995, in line with the APEC demand forecast, supply is predicted

to remain at around 30%, and given that there is a limit to the supply of high quality

coal within the region, the possibility is that coal supply and demand will grow tight in

the long-term is recognized, and more than a small security risk exists. For this reason

1


as well, it is recognized that striving to stabilize coal supply and demand in each

economy within the region is an important task.

Furthermore, in order to attempt to liberalize and facilitate coal trade and investment

within the APEC region, the following are important: (1) reduction of tariffs and

removal of non-trade barriers; (2) promotion of investment in coal-fired power stations;

and (3) providing sufficient explanations to regional societies. Countermeasures and

strategies are desired in every economy.

In forums such as the Conference of the Parties to the Framework Convention on

Climate Change (COP), we must sustain our efforts of reducing emissions of CO2,

NOX, SOX and so on involved in coal usage while large scale reductions in greenhouse

gases throughout the world are being called for. With its long history of coal usage, we,

Japan, recognize that this is a problem that must be tackled aggressively, and we believe

that it is a very important task for every economy here today.

For such reasons, by promoting the development of clean coal technologies such as

high-efficiency coal combustion technology, and furthermore through the Green Aid

Plan, we are actively conducting technology transfer with Asian economies of coal

utilization technologies, such as our desulfurization technology and coal preparation

technologies.

Copings with increased energy demand and with environmental issues in the Asia -

Pacific region like this are tasks that we must not forget. In the 21st century, coal will

be as important an energy as ever for Asia, and we believe it is essential to recognize

that striving to stabilize coal supply and demand within the APEC region, liberalize coal

trade and investment, and spread related technologies will continue to be important

themes.

On this occasion, two seminars and one workshop will be held jointly. We believe

that these will be extremely valuable opportunities for everyone from the each economy

within the APEC region to be able to meet together and exchange information and

opinions on each of the issues I have just mentioned. We hope that these seminars and

the workshop prove successful, and also hope that international network will continue to

grow in the field of coal in future.

Thank you.


Joint 8 th APEC Coal Flow Seminar and 9 th APEC Clean Fossil Energy

Technical Seminar

USA Official Welcome

Scott M. Smouse

Chair, APEC ong>Expertong> ong>Groupong> on Clean Fossil Energy

Senior Management & Technical Advisor – International

U.S. Department of Energy

National Energy Technology Laboratory

Good Morning. My name is Scott Smouse. I am the new Chair of the APEC ong>Expertong>

ong>Groupong> on Clean Fossil Energy, which has organized this event.

I would like to extend a warm welcome to all of the participants in the Coal Flow and the

Clean Fossil Energy Technical Seminar, and the TILF Workshop. We were honored this

morning to hear from the Honorable Leo Moggie, the Minister of Energy,

Communications and Multimedia for Malaysia about the opportunities and challenges

that Malaysia faces in developing its coal and power sectors.

I would like thank all of you for being here after postponement of this event from last

October. Your patience and support are greatly appreciated.

First a few words about myself as I have yet to meet many of you. For the last six years,

I have managed the International Program at the U.S. Department of Energy’s National

Energy Technology Laboratory or NETL. NETL is responsible for managing the U.S.

national fossil energy R&D program in coal, oil, and natural gas. Although I have been

only recently become active in the ong>Expertong> ong>Groupong>, I have been involved in other activities

in many of APEC economies in the past.

A week ago, I was expecting to be standing here this morning beside Dr. Sun Chun and

being introduced as the new Chair of the ong>Expertong> ong>Groupong>. Unfortunately, as some of you

may have heard, Dr. Chun can’t be here with us this week. However, I would take this

opportunity to personally thank Dr. Chun for his determination and excellent leadership

of the ong>Expertong> ong>Groupong> for the past four years. Under Dr. Chun’s tenure, not only did he

convene several successful workshops and seminars like this one, he also completed

several important studies and projects. He also expanded the mission of the ong>Expertong>

ong>Groupong> from its original Clean Coal Technology emphasis to include all fossil fuels by

adding an Oil and Gas Program along side the existing Coal Technology and Coal Policy

Programs, thereby creating the current ong>Expertong> ong>Groupong> on Clean Fossil Energy.

I can only hope to begin to fill Dr. Chun’s shoes, as we in America would say. Dr. Chun

will continue to provide leadership for the APEC Energy Security Initiative, which has

been recognized by the APEC Leaders as important activity. He also plans to be with us

at the next joint seminar, which will be held in China this fall.


I also would like to take a moment to thank Mr. Ken Hong, who served as the ong>Expertong>

ong>Groupong>’s Secretariat under Dr. Chun for the past four years. Ken has retired from

government service and is now spending more time with his family. At this time, I would

like to introduce Mrs. Susan Laczko, as the new Secretariat for the ong>Expertong> ong>Groupong>. Sue

has extensive international experience and will serve us well in that capacity.

I thank the members of the Project Steering Committee for their hard work in organizing

this event. Also, I would like to especially extend my thanks to the hosts for these

meetings, the Malaysian Ministry of Energy, Communications and Multimedia, and TNB

Fuel Services. They have selected an excellent facility for this event and put together

what looks to be interesting program and power plant site visits on Wednesday. I would

also like to acknowledge the financial and administrative support provided by the

Malaysian and Japanese governments in organizing this event.

It is with great pleasure that I take on the position of Chair of the ong>Expertong> ong>Groupong>. I hope

this week is a productive one for each of you. I look forward to talking to many of you on

a one-to-one basis throughout the week and getting to know you personally.

Before I conclude, I would like to say a few words about the coal situation in the United

States. While coal is recognized as the low-cost fuel for electricity generation around the

world, not only in coal-producing economies, like China, Indonesia, and United States,

but also in coal-importing economies, such as Japan, Korea, and Chinese Taipei. Coal is

at the center of the strength of many of our economies and is the fuel of choice upon

which our industries operate. The use of coal increases energy security through fuel

diversification. There is no other fuel so widely distributed around the world and reliably

available at steady prices from so many suppliers. This fact has been recognized in the

new National Energy Policy put forth by the U.S. Administration and I will speak more

about this tomorrow.

However, coal is not without its problems. For decades, coal’s principal problem was

emission of sulfur dioxide and nitrogen oxides, which cause acid rain. The United States

and other developed countries have greatly reduced this problem by developing and then

deploying SO 2 scrubbers and low-NO x burner technologies. More recently, issues, such

as mercury and fine particulate emissions, have become a concern in the United States

and other countries. And now, as we all know, the biggest threat to continued use of coal

worldwide is climate change.

Over the past decade, the United States has built very few new coal-fired power plants.

However, U.S. Energy Information Administration projects that the United States will

need to construct at least 62 new coal plants representing over 31 GW of new capacity by

2020 to meet future electricity demand. While these additions are small compared to the

amount of total new capacity that the United States is expected to build over that time

period, which is nearly 350 GW; the current situation is being considered by many to be

the rebirth of coal in the United States.


While is it uncertain how many of these new plants will use the new Clean Coal

Technologies, such as Integrated Gasification Combined Cycle (IGCC) or supercritical

pulverized-coal technology, certainly the new plants will have to be cleaner and more

efficient that the current fleet of power stations.

It is through open exchange of information and ideas, through meetings such as this, that

issues, such as climate change, can be discussed and debated. The public’s health must be

protected while providing at the same time recognizing that low-cost electricity is needed

to keep our economies vibrant. The ong>Expertong> ong>Groupong> on Clean Fossil Energy seeks to assist

APEC member economies in the economic development of their fossil energy sectors

while being a good steward of the environment.

I look forward to hearing from the all speakers this week to learn the latest information

on the technological and policy approaches that they are pursuing to allow the continued

use of coal in the APEC region and as a pillar for sustainable development around the

world in the 21 st century, which is the theme of this workshop.

THANK YOU.


SESSION 1:

Pacific Coal Flow

and Energy Security

Chair: Mr Scott Smouse

Senior Management and Technical Advisor

National Energy Technology Laboratory

Department of Energy (DOE)

USA


THE CURRENT SITUATION OF

ENERGY SUPPLY AND

DEMAND IN JAPAN

Mr Kazuo Sugiyama

Chairman

The Japanese Committee for Pacific Coal Flow

(JAPAC); and former President

Electric Power Development Co., Ltd (EPDC)

Japan


Abstract

This paper introduces the Japanese Energy Supply and Demand Outlook as well as the

comprehensive energy policy based on the report prepared by the Advisory Committee

of Energy and Natural Resources, the Ministry of Economy, Trade and Industry in July

2001.

Japan is now considering the ratification of the Kyoto Protocol, and should it be

ratified Japan will be obligated to reduce its GHGs emission 6% below the 1990 level by

2010. Reducing its energy-derived CO 2 emission to the 1990 level by 2010 is a

prerequisite for achieving this target.

Due to the delay in constructing new nuclear power plants, the energy consumption

increased in the transportation, residential and commercial sectors as well as coal as cheap

energy source. This has made it extremely difficult to reduce the CO 2 emission by 2010

to the 1990 level only with the current policies. It is estimated that additional CO 2

reduction of 20 million t-C should be required by 2010.

A proposed new energy policy is being proposed to reduce 6 million t-C of CO 2

emission by 2010 through further strengthening of energy conservation policies and

measures, while reducing additional 9 million t-C by further development and utilization

of renewable energy. Another reduction of 5 million t-C to be achieved by fuel shift from

coal to natural gas.

Having participated in the process as the vice-chair of the committee, I am supposed to

support the report. However, I have somewhat critical view of it.


Introduction

At the outset, I would like to express my appreciation to be given this opportunity to

speak on "The Current Situation of Energy Supply and Demand in Japan".

As an introduction, it may be appropriate for me to explain the outline of the report

published by the Advisory Committee on Energy and Natural Resources on July 12 th 2001

in response to a consultation requested by the Minister of Economy, Trade and Industry.

The report was produced after 78 discussion meetings and working groups over 15

months.

As the vice-chair of the committee, I am expected to support the report. However, I

would have to be somewhat be critical.

1. New Energy Supply-Demand Outlook

The outlook for energy supply and demand up to 2010, reported at the committee in

June 1998, was reviewed because both the supply and demand situation and outlook have

changed. The energy demand in the residential and transportation sectors has increased

beyond projection as well as the use of low coast coal. This combined with the

unexpectedly slow introduction of nuclear and renewable energy. Secondly, if we are to

follow the current path it would be impossible to achieve the GHGs reduction target set

out in the Kyoto Protocol, to reduce the energy derived CO2 Emission to the level of 1990.

And thirdly, the addition of a new target to reduce energy prices to the internationally

reasonable levels by further improving efficiency through deregulation and liberalization

on top of the three conventional targets of the 3E Japanese energy policy; to "achieve

economic growth", "ensure energy security" and "address global environmental issues".

2. Energy Supply and Demand Trends and Outlooks

(1) As is shown in Attachment 1, energy demand in Japan increased consistently

with the exception of the two oil crises. Energy consumption in 1999 was 402 million kl

crude oil equivalent or 60 % increase in 30 years, while GDP grew 2.1 times higher

during the same period. Therefore, energy use efficiency has been fairly good.

In 1990s, however, GDP growth was as low as 1.3 % per year, while energy

consumption grew as high as 1.6%. The energy elasticity to GDP was 1.3.

(2) Attachment 2 shows trends in final energy consumption by sector since 1973, when

the first oil crisis occurred. The industrial sector including manufacturing is almost flat


with minor increase due to improvement in energy use efficiency while in the other

sectors the figures have been growing sharply regardless of the economic situation: 2.7

times higher for the transportation sector (mainly passenger cars), 2.2 times higher for the

household sector and 1.9 times higher for the commercial sector including services for

buildings.

Detailed analysis is being conducted to figure out the causes of the increase in these

sectors, however, the main causes may be summarized as follows: increase in the number

of automobiles owned in suburban areas; increase in the number of individual households

due to the development of the aging society and nuclear families; the change of the

industrial structure such as the growth of the IT industry; and increase in floor space in

buildings due to the expansion of the service industry.

(3) Attachment 3 shows the energy consumption outlook. Energy consumption by

sector and its share to the total consumption are shown in this table. The figures for each

sector are given up to 1999, and the shares to the total of the industrial sector shows a

decline while a significant increase is noted in the residential and transportation sectors.

The outlook is given for two cases: a “Base Case” and “Countermeasures Case” (New

Target Case). “Base Case” refers to an outlook for energy consumption under the ongoing

energy conservation policy. “Countermeasure Case” (New Target Case) refers to an

outlook with a maximum energy conservation measures to cope with the global

environmental issues and achieving the CO 2 emission reduction target. In the

“Countermeasure Case”, the focus is to maintain the total energy consumption in 2010 at

the same level as in 1999. This outlook assumes an economic growth of 2% per year

while maintaining the present energy consumption level through energy conservation.

In the previously designed outlook the reduction of 50 oil equivalent million kl of

energy consumption had already been planned and compared to business-as-usual outlook,

through the introduction of “Keidanren 1 ” Environment Action Plan and a “top-runner

approach”. In the new outlook, however, an additional reduction of energy consumption

by 7 million kl is to be achieved by an energy conservation policy mainly for the

household, commercial, and passenger cars sectors, in which energy consumption is

growing sharply. Under this outlook CO 2 emission reduction by 2010 would be

approximately 6 million t C.

1 “Keidanren”: Association of the Industrial and Commercial major Private Companies in

Japan


3. CO2 Reduction Issues in Japan

Why reduce energy demand As you already know, the new Energy Supply-Demand

Outlook was developed on the premise that CO 2 emission must be controlled in order for

Japan to achieve the GHGs reduction target in the Kyoto Protocol.

Let me briefly talk about CO 2 emission reduction. The Kyoto Protocol adopted by

COP 3 in 1997 set the target for reducing the total GHGs emission by developed

economies 5% below the 1990 level from 2008 to 2012 (the first commitment period), the

breakdown of which is 6% for Japan, 7% for the U.S., and 8% for EU. In response to this,

Japan is to control its energy-derived CO 2 emissions – which accounts for 85% of GHGs

– to be on the 1990 level. For Japan, however, who has already anxiously improved the

efficient use of energy and has already achieved a high level, this target is extremely

difficult to meet. As seen in Attachment 4, its energy-derived CO 2 emissions accounted

for 313 million t-C in 1999, which have already been higher by 8.9% than 287 million t-C

in 1990. In the Base Case of the Energy Supply-Demand Outlook through to 2010, it

would be 307 million t-C, with the ongoing energy conservation measures only, which

would be 6.9%, that is 20 million t-C, higher than the 287 million t-C. That is why we

have decided to control energy consumption as much as we can by adding energy

conservation policies with maximum capability. However, as the maximum CO 2 emission

reductions only by energy consumption saving would be limited to 6 million t-C, we have

to consider how we could reduce the rest of the amount required, -- that is 20 million t-C –

6 million t-C = 14 million t-C --, from the supply side of energy.

4. Trend and Outlooks in Energy Supply

Attachment 5 summarizes the primary energy supply broken down by sector for 1990 -

1999, as well as the outlook for 2010 in the base and countermeasure (new target) cases in

terms of the same definition used for demand projection. It shows slower increase in

energy supply premised on the GDP growth of 2% per year: 0.4% per year for the “Base

Case” and 0.1% per year for the “Countermeasure Case” (target case).

First of all, regarding petroleum, reducing oil dependency is long and unchanged

objective of Japan’s energy policy, and the dependency was reduced to 52% in 1999 from

58% in 1990, and the objective is to achieve 45% by 2010. Meanwhile, the share of

Mid-East oil in the total crude oil imports was lowered to 70% in the latter half of 1980s

from 78% at the time of the first oil crisis. It has been increasing recently to 86%, a


challenge in ensuring energy security.

As for coal and natural gas, both supply and share are increasing. What is worthwhile

noting is that in the “Countermeasure Case”(new target case)), the figures for natural gas

increase while those for coal will be controlled by 2010.

The nuclear energy has gone through a major change from the previous outlook. In the

previous outlook, it was expected that a capacity of 66 to 70 million kW would be

achieved by constructing 17 to 20 units in addition to the 51 nuclear power units as of the

end of FY1999 (44.92 million kW, 316.5billion kWh). As a result the nuclear energy

would account for17% share in the primary energy supply. However, in the new outlook,

the number of newly constructed units by 2010 was revised to 13, with the total installed

capacity of approximately 60 million kW, the electric power generation of 418.6 billion

kWh, reflects the increased difficulty in acquiring new sites due to the accident in an

uranium processing plant, etc. The share of nuclear energy in the primary energy supply

has been revised downward to approximately 15%. Delay in the new construction of

nuclear power plants as non CO 2 -emitting sources will have a significant impact not only

on energy supply planning but also on achieving GHGs reduction in the Kyoto Protocol.

This was one of the reasons for this revision to the Energy Supply and Demand Outlook.

Moreover, I believe the construction of 13 new units will be difficult.

The share of renewable energy except hydro-power and geothermal (in Japan, this is

called “new energy”) in the primary energy supply in 1999 was only 1.3%, 693 kl oil

equivalent. The renewable energy is mainly obtained from waste fluid and scraps in the

pulp industry. Although it is said that the new energy will not be commercially viable and

that economic burden will be heavier, the target of 19.1 million kl oil equivalent has been

set in this revision as feasible, as seen in Attachment 6. This assumes that the maximum

efforts for cost reduction and technology development be addressed by the both public

and private sectors as well as assistance and support given by the government. This target

figure is equivalent to 3% of the primary energy supply. In addition, CO 2 emission could

be reduced by 9 million t-C. The total renewable energy including hydro-power and

geothermal would be 7% of the total primary energy supply in 2010.

5. Outlook for Power Sources and Coal

The attachment 7 covers Electricity Generating Facilities (kW) and attachment 8 the

electric power generation (kWh) from 1990 to 2010. I believe I have already sufficiently

explained the total picture when I spoke of the primary energy supply.

However, I would like to make brief comments on coal-fired power generation.


Attachment 7 shows the significant growth in the capacity of those plants due to the

additional construction of coal-fired power plants by electric utility companies as well as

the entry of independent thermal power producers (IPPs). This was the result of the

liberalization of the power industry in answer to a strong request to reduce power

generation costs.

According to my investigation, coal-fired power generation capacity as of the end of

FY 2000 was about 29 million kW and additional capacity under plan by power

companies and IPPs was in total approximately 15 million kW. This is consistent with 44

million kW for the “Base Case” in Attachment 7. However, as there are some plans

already announced to be cancelled or postponed, or those under consideration of doing so,

due to recent slowdown in power demand, this figure seems not likely to be achieved.

Another focus in Attachment 8 is that the electricity generation of coal-fired power

plants is substantially reduced in “Countermeasure Case” (target case) in 2010, despite the

significant growth in its installed capacity. The target electricity generation for 2010 is

stated as 159.9 billion kWh, although 170 billion kWh has already been reached in the

actual record for FY 2000.

This is based on an idea called “Fuel Shift in Power Sources”, which was presented by

the Secretariat of Agency of Natural Resources and Energy in the final stages of the

discussion in the Advisory Committee on Energy and Natural Resources. As I have

mentioned earlier, the reduction of 20 million t-C is required to lower the CO 2 emission to

the 1990 levels. Even if 6 million t-C could be reduced through enhanced energy savings

and 9 million t-C by the strengthening renewable energy development, another 5 million

t-C must be reduced. “Fuel Shift in Power Sources” is one solution. This implies guiding

the electric power industry to shift fuel for power generation from coal to natural gas

(LNG), with relatively less CO 2 emission in existing as well as in new plants. This means

either for IPPs and utility companies to voluntarily shift fuel or for the government to

provide subsidy to do so or regulate to discourage the use of coal that has cost benefit over

other types of fuel. This idea was mentioned in the report as an issue to be considered, but

no discussion has taken place on specific policy or measures. I said I am opposed to the

idea of suppressing the use of coal, which incidentally no other economy is doing, it

would be most foolish to reduce the availability factor of coal-fired plants, by means of

taxation, etc.. They were after all constructed under the government policy defining coal

as the main alternative source of energy replacing oil and supplying the cheapest power.

This does not apply to those plants that will be newly constructed. My opinion was

supported by many others but there seems to be no specific consideration of measures on

this issue after the report even within the Agency of Natural Resources and Energy. It is


extremely irrational to forcibly suppress the use of coal, which is important from the

perspective of Japan’s energy security and most effective in reducing electricity prices,

just because its CO 2 emissions are relatively higher among fossil energy. Prime Minister

Koizumi, however, expressed his opinion in the general policy speech during the current

session of that the Diet would pass the ratification of the Kyoto Protocol, which may

cause this issue to be brought up again. We should keep our eyes on it.

6. The Ratification of the Kyoto Protocol

I would like to briefly present my opinion regarding the irrationality of the Kyoto

Protocol. It goes without saying that long-term CO 2 emission control program should be

planned as soon as possible. As for coal, it is of course necessary to use it effectively as a

valuable resource given to man. Currently in Japan, Ultra Super Critical Power

Generation, with the generation efficiency of 41% at the line-end generation efficiency of

41%, has already been made practicable and other technology development, such as

Integrated Coal Gasification Combined Cycle Power Generation (IGCC) and Integrated

Gasification Fuel Cell Combined Cycle Power Generation (IGFC) whose target

generation efficiency is 44% and 55% respectively, is now being earnestly promoted. This

is not only for coal, but technology development to provide a breakthrough for CO2

emission must be further promoted in every sector of energy production and consumption

regardless of the time it takes. This must be diffused to developing economies that will

undergo industrialization in the future. This should be the right path for solving the global

environmental issues. Yet it must not to be accomplished through regulations and tax

systems that will pressure individual firms..

It is an extremely difficult challenge for Japan to bring CO 2 emission back to the 1990

level by 2010 as we have established the most efficient society in energy production and

consumption due to the efforts made after the oil crises.

Considering significant costs for further CO 2 emission reduction in Japan compared to

Germany, who is restructuring its inefficient production system drastically after the

integration with former East Germany in 1990, and the U.K., who has switched from its

domestic coal to natural gas coming from the North Sea fields, it can be said the GHGs

reduction targets of 8% for EU and 6% for Japan are extremely unfair. In addition, it

would be extremely dangerous for Japan to solely ratify the Kyoto Protocol while the U.S.

who is responsible for one fourth of the world CO 2 emission and one third of developed

economies’ CO 2 emission has dropped out, and developing economies that would be

responsible for half of the world’s CO 2 emission in 2020 do not assume any reduction


obligations. Recently, “Keidanren” and the Japan Chamber of Commerce and Industry

have shown their view that they are against taking the risk of ratifying the Kyoto Protocol

for the time being, indicating the danger o weakening industrial competitiveness,

de-industrialization, and the increase of unemployment. We should keep our eyes on a

movement around ratification in the current Diet session.

7. Deregulation in the Electricity Industry

I would like to conclude my presentation by talking about the deregulation of the

Japanese utility industry.

Almost two years have passed since the power retail business was partly liberalized, in

March 2000. The central government and local municipalities are concluding their power

supply contracts through competitive bidding. On the other hand nine companies

including major trading houses, gas utilities, and iron & steel mills applied for entry into

the utility market. However, their capacity limited as they are just reselling surplus

electricity generated in-house by material producers such as iron and steel mills. Their

market share is less than 1%. This is far from the introduction of genuine competition.

The Ministry of Economy, Trade and Industry is now reviewing the power deregulation

scheme. By the end of this year it will present their conclusion on such issues as

reviewing the power industry system including the expansion of deregulation, pros and

cons for the establishment of the electricity pool market and power transmission rule

between the new comer and power utility companies. This trend of deregulation of the

power industry has caused a substantial reduction of electricity rates. Each electric utility

company in Japan has implemented a rates reduction of approximately 5% in October

2000, and additional reduction is scheduled this spring. With expanded deregulation,

further rates cut is likely in the future as well. As a result, enhanced sensitivity to fuel

prices and a diversity of fuel supply would be required. In the future there will be greater

sensitivity to fuel prices due to the possibility of losing the economic advantage of coal as

mentioned above as well as the need to reduce electricity rates in Japan.

Thank you very much for your kind attention.


The Current Situation of

Energy Supply and Demand in

Japan

Kazuo Sugiyama

Chairman, JAPAC

Former President, EPDC


Attachment 1

Final Energy Consumption

Unit: Million kl Crude Oil Equivalent

400

396

402

350

Second Oil Crisis

392

300

First Oil Crisis

285

301

349

250

200

70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99

Year

(Source) Comprehensive Energy Statistics


Attachment 2

Final Energy Consumption by Sector


Attachment 3

Summary of Long-Term Energy Supply

and Demand Outlook

(unit: Million kl Crude Oil Equivalent)

Year

FY 1990

Item Shares %

FY 1999

FY 2010

Base Case Countermeasure Case

Shares % Shares % Shares %

Industrial 183 52.5 197 49.0 187 45.8 185 46

Residential 85 24.4 105 26.1 126 30.8 120 30

Household 46 13.3 55 13.8 60 14.7 58 14

Commercial 39 11.2 50 12.3 66 16.1 63 16

Transportation 80 23.0 100 24.9 96 23.4 94 24

Passenger 39 11.0 53 13.2 51 12.5 50 12

Freight, etc 42 12.0 47 11.7 45 10.9 45 11

Total 349 100 402 100 409 100 400 100


Attachment 4

CO 2 Reduction Scenario

(Countermeasure Case)

Energy-Derived CO2

Emission (M t-C•j

350

Base Case Business-as-Usual Case (1998) Countermeasure Case

347Mt-C

330

310

290

270

Actual Value for

FY1990

287Mt-C

Actual Value for

FY1999

313Mt-C

Difference of 20Mt-C

307Mt-C

287Mt-C

250

230

1985 1990 1995 2000 2005 2010

(Year•j


Attachment 5

Trend and Outlook in

Primary Energy Supply

FY 1990 FY 1999

(Unit: Million kl Crude Oil Equivalent )

FY 2010

Base Case Countermeasure Case

Primary Energy Supply

526 593 622 602

Types of Energy Supply Actual Share % Actual Share % Share % Share %

Oil 307 58.3 308 52.0 280 45.0 271 45

Coal 87 16.6 103 17.4 136 21.9 114 19

Natural Gas 53 10.1 75 12.7 82 13.2 83 14

Nuclear 49 9.4 77 13.0 93 15.0 93 15

Hydro 22 4.2 21 3.6 20 3.2 20 3

Geothermal 1 0.1 1 0.2 1 0.2 1 0.2

New Energy, etc 7 1.3 7 1.1 10 1.6 20 3

Renewable Energy* 29 5.6 29 4.9 30 4.8 40 7

*Note•j Renewable Energy includes New Energy, Hydro and Geothermal.


Attachment 6

Targets for Renewable Energy Excluding

Hydro and Geothermal

Oil Equivalent

Installation

Capacity

Oil Equivalent

Installation

Capacity

Oil Equivalent

Installation

Capacity

( 1,000kl) ( MW) ( 1,000kl) ( MW) ( 1,000kl) ( MW)

Photovoltaics 53 209 620 2,540 1,180 4,820 23 times

Wind Power 35 83 320 780 1,340 3,000 38 times

Waste Power 1,150 900 2,080 1,750 5,520 4,170 5 times

Biomass Power 54 80 130 160 340 330 6 times

Solar Thermal

Utilization

Unused Energy

(snow, ice &

cryogenic heat)

Waste Thermal

Utilization

Biomass Thermal

Utilization

Waste Fluid & Scrap

Wood

Total New Energy

Supply

FY 1999

Base Case

FY 2010

Countermeasure Case

2010/1999

980 - 720 - 4,390 - 4 times

41 - 93 - 580 - 14 times

44 - 44 - 140 - 3 times

- - •| - 670 - •|

4,570 - 4,790 - 4,940 - 1.1 times

6,930 - 8,780 - 19,100 - 3 times


Attachment 7

Trend and Outlook in Installed Capacity &

Electricity Generating Plans at Fiscal Year End

Item

Year

Installed Capacity at

Fiscal Year End

(Electric Utilities)

FY 1990

FY 1999

Base Case

FY 2010

Countermeasure Case

172,120 224,100 266,570 252,880•`272,290

(Unit: M W)

Generation Type Actual Share (%) Actual Share (%) Share (%) Share (%)

Thermal 104,080 60.5 134,340 59.9 153,430 57.6 146,700•`162,200 57.0•`59.6

Coal 12,230 7.1 24,880 11.1 44,100 16.5 31,550•`44,130 12.3•`16.2

‚k‚m‚f 38,390 22.3 56,770 25.3 67,020 25.1 66,060•`66,960 24.6•`26.1

Oil, etc 53,470 31.1 52,700 23.5 42,310 15.9 49,080•`51,110 18.8•`19.4

Nulear 31,480 18.3 44,920 20.0 61,850 23.2 57,550•`61,850 22.7•`24.1

Hydro 36,320 21.1 44,330 19.8 50,710 19.0 48,100 17.7•`19.0

Ordinary 19,310 11.2 20,020 8.9 20,700 7.8 20,690 7.6•`8.2

Pumping-up 17,010 9.9 24,310 10.8 30,010 11.3 27,410 10.1•`10.8

Geothermal 240 0.1 520 0.2 590 0.2 540 0.2

Note: The figures in the above outlook are calculated on a particular assumption, and should be

understood with a certain degree of tolerance.


Item

Attachment 8

Trend and Outlook in Electric Power

Generation by Power Sources

Electric Power

Generation

Power Types

Year

Actual

Share

(%)

Actual

Share

(%)

Share

(%)

(Unit: 100Million kWh)

Thermal 4,466 60.5 5,063 55.2 5,074 49.3 4,680 47.0

Coal 719 9.7 1,529 16.7 2,351 22.8 1,599 16.0

‚k‚m‚f 1,639 22.2 2,405 26.2 2,341 22.7 2,549 26.0

Oil, etc 2,108 28.6 1,129 12.3 383 3.7 533 5.0

Nuclear 2,014 27.3 3,165 34.5 4,186 40.7 4,186 42.0

Hydro 881 11.9 893 9.7 966 9.4 952 10.0

Ordinary 788 10.7 769 8.4 803 7.8 803 8.0

Pumping-up 93 1.3 123 1.3 163 1.6 149 1.0

Geothermal 15 0.2 34 0.4 37 0.4 37 0.4

New Energy - - 21 0.2 29 0.3 115 1.0

CO 2 Emission Intensity

•i g-c/kWh•j

FY 1990 FY 1999

Base Case

7,376 9,176 10,292

101.9 89.9 82.6

FY 2010

Countermeasure Case

Note: The figures in the above outlook are calculated on a particular assumption, and should be

understood with a certain degree of tolerance.

9,970

73.6

Share

(%)


Thank you for your attention!!


THE WORLD COAL MARKET:

PROSPECTS TO 2010

Ms Jane Melanie

Senior Economist

International Energy Program

Australian Bureau of Agricultural and Resource

Economics (ABARE)

Australia


ABARE CONFERENCE PAPER 02.6

Global coal markets

Prospects to 2010

Jane Mélanie and Karen Schneider

The 8th APEC Coal Flow Seminar

‘Coal in Sustainable Development in the 21st Century’

Kuala Lumpur, 4–5 March 2002

Coal accounts for almost a quarter of the world’s primary commercial energy

consumption and is expected to remain a key component of the energy mix in

most regions over the next decades. However, there are many factors that will

influence global and regional prospects for coal over the period to 2010.

Economic growth, sectoral shifts in the composition of output and energy technology

choices will continue to play a large part in shaping the future demand

for coal. Interacting with these broad parameters are a number of specific

policy initiatives that could have a significant bearing on coal consumption

over the next decade. These include initiatives related to energy market reform

and environmental issues. The outcome for coal markets over the next decade

will depend not only on the coal demand profiles emerging from these developments

but also, importantly, on how major coal producers respond to these

trends.

This paper summarises the principal findings of a major study recently

published by ABARE on the prospects for global coal markets over the period

to 2010. The key objective in that study is to assess the long term prospects

for world coal markets by developing projections for coal consumption, production

and trade in the period to 2010. The analysis in the study is based on

applications of ABARE’s model of world coal markets, GTEM-Coal.

ABARE project 2686

1


ABARE CONFERENCE PAPER 02.6

Introduction

Coal accounts for almost a quarter of the world’s primary commercial energy consumption

and is expected to remain a key component of the energy mix in most regions over

the next decades. This appears even more likely in the light of recent developments that

point to a resurgence of interest in coal for electricity generation in several key markets.

However, there are many factors that will influence global and regional prospects for coal

over the period to 2010. Economic growth, sectoral shifts in the composition of output

and energy technology choices will continue to play a large part in shaping the future

demand for coal. Interacting with these broad parameters are a number of specific policy

initiatives that could have a significant bearing on coal consumption over the next decade.

These include initiatives related to energy market reform and environmental issues. The

outcome for coal markets over the next decade will depend not only on the coal demand

profiles emerging from these developments but also, importantly, on how major coal

producers respond to these trends.

This paper summarises the principal findings of a major study published by ABARE on

the prospects for global coal markets over the period to 2010 (Mélanie et al. 2002). The

key objective in that study is to assess the long term prospects for world coal markets by

developing projections for coal consumption, production and trade in the period to 2010.

The focus is specifically on ‘hard’ coal, including both thermal coal and coking coal.

In the first part of the study, reference case or ‘business as usual’ projections are developed

that represent the likely outlook for coal in the absence of major new policies. In the

second part, the potential impacts of new policy initiatives or other important developments

that are likely to affect coal markets over the next decade are analysed. These are

the liberalisation of electricity markets, the removal of coal production and consumption

subsidies, the implementation of climate change policies, and changes in productivity

growth in the coal supply chain. The results of two of these simulations — electricity

market liberalisation and climate change policies — are reported in this paper.

Analytical framework

The key tool used in the study to analyse long term trends affecting the coal market is

GTEM-Coal, a specific module of ABARE’s global trade and environment model (GTEM).

GTEM is a multiregion, multisector, dynamic general equilibrium model of the world

economy. These features make GTEM an effective tool for analysing energy markets where

interactions between sectors and between economies is significant.

GTEM-Coal builds on this capacity by incorporating additional features that enhance

ABARE’s capacity to analyse international coal markets. These features include:

• a comprehensive treatment of different types of coal — brown thermal coal, black thermal

coal and coking coal;

2


ABARE CONFERENCE PAPER 02.6

• identification of the world’s key coal supply and demand regions;

• a detailed representation of technological change and interfuel substitution possibilities

in the industries that are the primary users of coal, namely electricity generation

and iron and steel; and

• the capacity to analyse the most important policy issues that are likely to determine the

future direction of the coal market, including energy market liberalisation and international

climate change responses.

As a dynamic model, GTEM-Coal requires a reference case or ‘business as usual’ simulation

against which the impacts of a policy change can be measured. The reference case

projects growth in key variables in a region, including income, labor supply and investment

and the associated growth throughout the rest of the economy, in the absence of

significant policy changes. The reference case provides a benchmark against which to

compare the influence of potential or likely policy initiatives, including electricity market

deregulation and the implementation of climate change response policies.

Results in the policy simulations are interpreted as deviations from the reference case. The

influence of electricity market liberalisation, for example, can be isolated by comparing

economic growth, sectoral output and investment,

coal consumption and trade, and other

variables in the simulation against those in the

reference case scenario.

In developing the reference case in this study,

two key assumptions have been imposed. The

first of these relates to projected gross domestic

product growth rates in the regions identified

in the analysis. The GDP growth rates used

in the study are based on historical data from

1995 to 1999 from the International Monetary

Fund (IMF 2000). Long term projections to

2010 are from ABARE. These are shown in

table 1.

A further key assumption is the fuel mix for

electricity generation. The shares of electricity

produced by different fuels (black coal, brown

coal, oil, gas, nuclear, hydropower and other

renewables) to 2010 are determined exogenously

(outside the model) in the reference case

on the basis of government and other projections

(table 2). The assumptions in table 2

reflect a wide range of factors that affect fuel

3

Table 1: GDP assumptions: reference case

Average annual growth

2000–10

%

Australia 3.5

United States 3.0

Canada 3.1

Germany 2.6

United Kingdom 2.5

Rest of European Union 2.7

Former Soviet Union 3.9

Eastern Europe 4.1

Japan 1.5

Other developed a 3.1

China 7.0

Korea, Rep. of 5.0

Chinese Tapei 5.0

India 5.5

Rest of South Asia 5.4

Indonesia 5.5

Rest of ASEAN 5.0

Middle East 4.0

South Africa 4.0

Colombia 4.3

Venezuela 4.2

Rest of World 4.7

a Comprises New Zealand, Norway, Switzerland and

Iceland.


ABARE CONFERENCE PAPER 02.6

Table 2: Share of electricity generated by each fuel under the reference case

Brown coal Black coal Oil Gas Nuclear Other

Region 1998 2010 1998 2010 1998 2010 1998 2010 1998 2010 1998 2010

% % % % % % % % % % % %

Australia 24.1 20.7 56.0 59.5 1.1 0.9 9.0 12.0 0.0 0.0 9.8 6.9

European Union 7.6 6.0 22.7 15.0 6.7 4.2 17.0 32.0 33.7 26.8 12.3 16.1

Japan 0.0 0.0 19.1 22.0 6.4 9.0 21.1 22.0 32.1 36.0 11.3 11.0

North America 2.9 2.9 46.5 45.3 3.8 0.4 13.7 20.8 18.2 16.5 15.0 14.1

Other developed a 0.0 0.0 0.8 1.6 0.2 0.1 4.4 4.1 11.7 10.1 82.9 84.1

Transition

economies 18.3 17.9 19.0 10.2 5.9 5.6 25.5 37.2 16.5 11.6 14.9 17.4

ASEAN 5.4 3.3 11.3 22.6 29.0 12.9 39.2 48.8 0.0 0.0 15.1 12.3

China 0.0 0.0 75.5 73.2 4.4 4.1 1.5 3.2 1.2 1.9 17.5 17.5

Chinese Tapei 0.0 0.0 42.6 44.0 20.5 6.0 8.5 21.0 22.0 21.0 6.5 8.0

India 2.4 0.5 73.0 69.5 0.7 2.0 4.7 9.0 2.3 2.0 16.8 17.0

Korea, Rep. of 0.0 0.0 40.9 37.6 6.1 7.9 11.2 10.6 38.1 41.3 3.7 2.6

Other developing 4.2 2.6 11.3 13.2 22.7 18.9 20.6 25.9 1.8 1.8 39.4 37.5

a Comprises New Zealand, Norway, Switzerland and Iceland.

and technology choices for electricity generation, including relative costs, available technologies,

environmental factors and energy security considerations.

Reference case outlook

Coal consumption and imports

In the reference case, global coal consumption is projected to grow by 1.9 per cent a year

between 1999 and 2010 to reach 4.2 billion tonnes in 2010 (figure 1). Compared with

coal’s performance over the 1990s, this is a relatively strong growth rate and one that is

expected to maintain coal’s share of world primary energy consumption at around 25 per

cent. This outcome is driven largely by thermal coal consumption, which is expected to

grow by 2 per cent a year over the outlook horizon. China and India are projected to account

for around 60 per cent of the absolute increase

in world thermal coal consumption. Global

consumption of coking coal is projected to

Figure 1: World hard coal consumption,

reference case

grow moderately, at around 1 per cent a year,

over that period.

4000 Total

There are significant differences across regions

in the rate of growth in coal consumption, with

the strongest growth expected to occur in Asia

(figure 2). Reversing the downward trend that

emerged in the late 1990s, coal consumption

in China is projected to increase by 2.7 per cent

a year to reach 1.35 billion tonnes in 2010 —

4

3000

2000

1000

Mt

Thermal

Coking

2000 2002 2004 2006 2008 2010


ABARE CONFERENCE PAPER 02.6

Figure 2: Average annual change in world hard coal consumption, by region, 1999–2010,

reference case

8

6

4

2

%

–2

Developed

Transition

economies

Developing

Australia

Japan

North America

European Union

China

India

ASEAN

Korea

Chinese Taipei

a level slightly below its peak in 1996. This projection is underpinned by higher economic

growth assumptions, offset to some extent by continuing improvements in the efficiency of

coal use in the industry sector and in electricity generation, and declining direct use of

coal in the residential sector as personal incomes rise (see box 1).

Coal is also projected to play an important role in other developing Asian economies. In the

ASEAN region, for example, thermal coal consumption is projected to rise by 9.5 per cent

a year over the period to 2010. This implies that ASEAN coal consumption could be almost

50 million tonnes higher in 2010 than it was in 1999. The most rapid growth in coal

consumption in the region is projected to occur in the coal importing economies of

Malaysia, Thailand and the Philippines.

Similarly, thermal coal consumption is projected to increase rapidly in the Republic of

Korea and Chinese Taipei, where coal imports are already significant. In both the ASEAN

and north east Asian economies, the growth in coal consumption reflects, principally, an

increased reliance on coal for electricity generation.

Contributing to the growth in global thermal coal consumption is the renewed interest in

expanding coal fired electricity generation capacity in a number of key advanced economies,

including the United States, Japan and Australia. This reflects the increasing competitiveness

of coal as a fuel for electricity generation. In Japan, thermal coal consumption is

expected to grow more rapidly than electricity consumption, underpinned by an additional

20 gigawatts of coal fired generation capacity expected to be commissioned by 2009. This

is despite delays in the construction of new power plants in recent years owing to uncertainties

related to economic growth, deregulation of energy markets, technological development

and climate change policies.

Emerging markets in Asia are also expected to provide the main impetus for world coking

coal consumption, reflecting the large potential for expanding iron and steel production

in line with rising incomes and increasing expenditure on infrastructure projects. In compar-

5


ABARE CONFERENCE PAPER 02.6

Box 1: China’s coal consumption

The projected increase in coal consumption in China is noteworthy in the light of recent trends.

Although there is still considerable uncertainty about recent Chinese coal statistics, the International

Energy Agency estimates that China’s coal consumption fell by 16 per cent between 1996 and

2000, from 1.37 billion tonnes to 1.15 billion tonnes (IEA 2001a).

The downturn in consumption can be attributed to a wide range of factors. A slowing in the rate of

economic growth since 1996, for example, has led to lower growth in electricity output and in the

demand for energy from some industrial subsectors, including building materials and chemicals

(Sinton and Fridley 2000). The reform of state owned enterprises — a key element of China's

economic policy — is leading to some significant industrial restructuring. The closure of many

state owned factories that were large and inefficient users of energy is having a positive impact on

energy efficiency in the industry sector. An increasing proportion of industrial output is from newer

and better operated enterprises in the nonstate sector.

Policies in the power generation sector to eliminate

small inefficient generators have also led

to reduced growth in China’s coal use. The

central government has strengthened its commitment

to close power plants of less than 50

megawatts — approximately 2.8 gigawatts of

small plants were closed in 1997 and 1998 and a

further 1.8 gigawatts in 1999. This means that

the average size of power plants in China is

rising and with this the average efficiency of

electricity generation. Residential coal use is also

falling as more urban dwellers move into apartments

with central heating and as consumers

switch to electricity and gas for cooking and

other residential energy services, as shown in

the graph.

Household energy consumption in China

1988 1990 1992 1994 1996 1998

The implications of these trends are still relatively uncertain at this stage and will depend on how

enduring the underlying changes prove to be. This is difficult to determine with any certainty, in

large part because of the preliminary nature of available data. In developing the coal consumption

projections for China in this study it is assumed that economic growth is higher on average than it

was in the period from 1998 to 1999, leading to an upward impact on the demand for coal.

However, offsetting this to some extent are assumptions that improvements in the efficiency of coal

use in the industry sector and in electricity generation will continue, although at a declining rate,

over the projection period. This is based on the continuing commitment of the Chinese government

to economic reform and to strengthening the efficiency of industrial enterprises and the power

sector. It is also assumed that the trend toward declining direct use of coal in the residential sector

will continue as rising personal incomes allow the purchase of more convenient and cleaner forms

of energy. As a result, China’s coal consumption is forecast to rise over the projection period, reversing

the trend of the late 1990s, but at a lower rate than in earlier years.

80

60

40

20

Mtoe

Coal

Electricity

Gas

6


ABARE CONFERENCE PAPER 02.6

ison, coking coal demand in more mature

economies is projected to remain flat as a result

of subdued growth in steel demand, the steady

shift toward electric arc furnaces and technological

enhancements affecting the efficiency

of blast furnaces.

As a large proportion of the projected growth

in coal consumption is expected to be in

regions that have limited indigenous coal

reserves, the reference case projections include

an increase in coal imports in most coal

importing economies (figure 3). World traded

Figure 3: World hard coal imports,

reference case

2000 2002 2004 2006 2008 2010

coal is projected to reach 650 million tonnes in 2010, compared with 520 million tonnes in

1999. The majority of trade is in thermal coal, which is projected to reach 440 million

tonnes in 2010. Coking coal trade rises to around 215 million tonnes in that year.

In the period to 2010, the north east Asian economies of Japan, Korea and Chinese Taipei

are expected to remain the largest importers of both thermal and coking coal. Japan, the

world’s largest coal importer, is projected to import 93 million tonnes of thermal coal.

The outlook for coking coal consumption and imports is expected to be relatively weak

in Japan. Japan’s share of world traded coking coal is projected to fall from 33 per cent

in 1999 to 31 per cent in 2010. Nonetheless, Japan will remain the single largest importer

of coking coal over the outlook period, with imports rising moderately to 67 million tonnes

in 2010. Korea and Chinese Taipei are projected to increase their imports of thermal coal

and coking coal by 36 per cent and 46 per cent respectively between 1999 and 2010.

However, the highest rate of growth for imported thermal coal is likely to come from the

ASEAN economies (figure 4). Thermal coal imports to the ASEAN region as a whole are

projected to reach 30 million tonnes in 2010, an increase of 14 per cent a year from a 1999

base.

600

500

400

300

200

100

Mt

Total

Thermal

Coking

Figure 4: Average annual change in world hard coal imports, by region, 1999–2010,

reference case

14

12

10

8

6

4

2

%

–2

ASEAN

Chinese

Taipei

India

Japan

Korea

North

America

European

Union

Transition

economies

7


ABARE CONFERENCE PAPER 02.6

A key uncertainty in relation to world demand for imported thermal coal is Indian coal

imports. Given that India has vast coal reserves, the projected growth in Indian coal demand

is expected to be met principally by domestic production. According to ABARE’s projections,

Indian thermal coal imports are expected to remain below 10 million tonnes in the

reference case. One of the main factors constraining Indian imports of thermal coal is the

continuation of the current domestic producer support arrangement in the form of an effective

tariff rate of 30 per cent on imported thermal coal. However, Indian thermal coal

imports could be significantly higher than projected if the import duty on coal were reduced.

Coal production and exports

Global growth in coal consumption is projected to be met by higher production volumes in

most major coal producing countries. The exceptions are Europe and the former Soviet

Union where coal industry rationalisation is expected to continue (figure 5). There is

considerable uncertainty, however, in relation to Russia’s coal production and export potential.

Coal production in the Russian Federation increased for the first time in 1999 after

almost a decade of industry restructuring, and labor productivity in the sector is reported to

be increasing. If this momentum is maintained over the outlook period, coal production

in the Russian Federation can be expected to rise. Nonetheless, a major turnaround in

Russian coal production capacity is unlikely to be sustainable without a substantial injection

of foreign capital, price reform and infrastructure development to facilitate both domestic

deliveries and exports.

For major coal exporters with adequate investment in production, transport and port capacities,

the projected growth in the demand for imported coal provides significant opportunities

to expand coal exports (figure 6). The reference case projections in this study highlight

Australia’s position as the world’s dominant coal exporter over the outlook horizon.

With minimal growth in exports of coking coal expected from the United States and

Canada, Australia is projected to increase its share of the international coking coal market

from 49 per cent in 1999 to 54 per cent in 2010. Australia’s coking coal exports are

projected to reach 115 million tonnes in 2010.

Figure 5: Average annual change in world hard coal production, 1999–2010,

reference case

4

3

2

1

%

–1

–2

–3

–4

Australia

United

States

Canada

European

Union

Transition

economies

China

India

Indonesia Latin

America

South

Africa

8


ABARE CONFERENCE PAPER 02.6

Figure 6: World hard coal exports, 1999–2010, reference case

5

4

3

2

1

%

–1

Australia

Canada

China

Indonesia

Latin

America

South

Africa

Transition

economies

United

States

The competition for market shares in the world traded thermal coal market will be more

intense. While Australia is also expected to remain the dominant supplier of thermal coal

in the international coal market, mounting competitive pressures from emerging thermal

coal suppliers to Asia — particularly from China — will influence Australia’s market position.

Following the sharp increase in thermal coal exports in recent years, the prospects for coal

producers in China to capitalise further on their vast coal reserves and proximity to the

Asian market are significant. However, China’s coal export performance is highly sensitive

to developments in its domestic market. Coal exports from China accounted for less than

5 per cent of total production in 2000, but for close to 18 per cent of coal traded in the

Asia Pacific region in that year. This implies that small changes at the domestic level in

China can generate significant ripples in the Asian coal market. Further, it appears that

government intervention in the coal industry in China has been instrumental in the push

to increase coal exports since 1999 and it is conceivable that this trend will continue in

the future.

In view of these uncertainties, ABARE has analysed a wide spectrum of potential thermal

coal export volumes from China ranging from 60 to 100 million tonnes in 2010 in an

attempt to capture the implications for competing coal exporters. The modeling results

indicate that higher coal exports from China will be at the expense of other major thermal

coal exporters such as Australia and Indonesia, and to a lesser extent South Africa (see

box 2).

Indonesian coal export potential in the period to 2010 adds another element of uncertainty

to the outlook for thermal coal trade. Indonesian coal exports increased steadily throughout

the 1990s, largely as a result of extensive marketing efforts to heighten the acceptance

of lower priced, high moisture, low energy sub-bituminous coal, particularly in the Asia

Pacific region. While Indonesian coal production is highly competitive by international

standards, Indonesia’s export potential over the projection period will depend to some

extent on the perceived risks attached to investment in the coal mining sector. The coal

industry in Indonesia is facing a range of legal, governance and human capacity building

9


ABARE CONFERENCE PAPER 02.6

Box 2: Implications of alternative Chinese coal export growth paths

Coal exports from China in the period to 2010 are likely to be driven more by policies than by

markets. Two scenarios are considered in order to determine the implications of potential policy

driven outcomes for competing coal exporters to Asia. It is assumed that Chinese thermal coal

exports reach 80 and 100 million tonnes in 2010, an increase of around 50 and 100 per cent respectively

relative to actual levels in 2000.

The results illustrate that exports of thermal coal by all other major exporters to the Asian region

decline relative to the reference case, as shown in the table below. The countries most affected are

Australia and Indonesia, with a 7 per cent and 8 per cent reduction in thermal coal exports respectively

in the 80 million tonnes scenario. South African coal exports are also adversely affected,

although to a lesser extent because the majority of South African exports is destined for the European

market. However, the total reduction in thermal coal exports by major exporters other than China is

lower than the assumed increase in Chinese exports. This reflects the dampening effect of additional

Chinese coal exports on the world market price for coal. This, in turn, leads to higher demand

for world coal, which offsets to some extent the reduction in coal exports by other economies.

However, the combination of lower export volumes and lower world price implies an even larger

reduction in the value of trade of competing exporters.

Thermal coal exports from China and competing suppliers

Change in coal exports, relative to the reference case

Assumed coal exports,

China 2010 Australia Indonesia South Africa

Mt % % %

80 –7 –8 –4

100 –12 –13 –6

challenges in the transition to regional autonomy. To the extent that these risk factors

continue to affect the mining sector, they can be expected to have an adverse impact on

mining exploration and coal production and exports in Indonesia.

To assess the potential outcomes for Indonesian coal exports, ABARE has undertaken a

sensitivity analysis that assumes that these risks raise the implicit cost of Indonesian coal

production by 10 per cent in 2010. Under these circumstances, Indonesian coal exports

are projected to grow to only 60 million tonnes by 2010, compared with 76 million tonnes

in the reference case where a return to stable political and economic conditions is assumed.

Policy simulations

There is a range of policy issues that could affect the reference case projections for coal

markets presented above. These include market liberalising initiatives such as deregulation

of electricity supply industries and the removal of energy production and consumption

subsidies; the implementation of stringent environmental standards, including global

10


ABARE CONFERENCE PAPER 02.6

climate change policies; and productivity growth in the coal supply chain. The impacts of

two of these issues — electricity market liberalisation and climate change policies — are

addressed below.

Electricity market liberalisation

Electricity supply industries in many economies are undergoing a period of quite significant

change. The reform agenda is being driven by the imperative to deliver electricity

services in the most efficient manner possible and at competitive prices while ensuring

sufficient financial capacity to invest in system expansion. With more than 60 per cent of

world coal consumed by the power sector and virtually all the projected growth in coal

consumption likely to be confined to that sector, reform of electricity markets could have

important implications for the reference case projections in the period to 2010.

This is because competition in electricity supply is expected to lead to increased productivity

in the industry and to contribute to lower electricity prices. Because electricity is an

important input to economic activity, lower electricity prices could provide a significant

productivity boost to economies that implement reforms and lead to higher economic

growth. This, in turn, will have implications for the level of energy consumption. Increased

competition in the electricity market could also influence the mix of fuels used in power

generation because it will tend to increase the pressure on fuel prices and to favor the

lowest cost generation technologies.

The impacts of electricity market restructuring can be expected to vary across countries

because of their different structural and policy contexts, and the varied nature of the

proposed reforms. To the extent that countries undertaking liberalisation are significant

players in the world traded coal market, changes in coal consumption patterns at the domestic

level can be expected to influence coal market outcomes at the international level.

To illustrate the potential impacts of electricity sector liberalisation on coal consumption

and trade over the period to 2010, GTEM-Coal is used to analyse the electricity reform

process proposed in three north east Asian economies — Japan, the Republic of Korea

and Chinese Taipei. These three countries are all seeking to improve the efficiency of their

electricity sectors by introducing competition at all levels of the electricity supply chain

(Fairhead et al. 2001). While the reform models being developed differ across the three

economies and the implementation of the reform plans is at different stages, there are

common elements across all programs. These include the unbundling of the generation

sector from the transmission and distribution sectors, the expansion of independent power

producers, open access to the networks and the deregulation of power sales to progressively

smaller retail customers.

The model results indicate that enhanced productivity and lower prices following electricity

deregulation are likely to lead to increased demand for goods and services in the

three economies. This results in GDP rising above reference case levels. In addition, when

11


ABARE CONFERENCE PAPER 02.6

Figure 7: Impacts of deregulation on sectoral output, 2010

Relative to the reference case

0.8

0.6

Japan

Korea

Chinese Taipei

0.4

0.2

%

Iron and

steel

Non-ferrous

metals

Chemicals,

rubber

and plastics

Other

manufacturing

Trade and

transport

Services

the price of electricity falls following deregulation, the competitiveness of the region’s

electricity intensive sectors improves relative to other sectors of the economy and relative

to energy intensive production in other economies. As a result, output of these industries

rises above their reference case levels (figure 7). This results in some reallocation of the

economy’s resources and, together, electricity

intensive industries account for a larger share

of economic output than in the reference case.

The net effect of these structural impacts

following deregulation is that economic activity

in north east Asia at 2010 is more electricity

intensive than in the reference case (figure

8). That is, the price and other impacts of

deregulation mean that more electricity is used

to produce a given amount of GDP after deregulation

than in the reference case situation.

Given the increases in economic output and in

electricity intensity, it follows that electricity

consumption in the three economies will be

higher after deregulation than in the reference

case (figure 9). Across the region, electricity

consumption at 2010 is 37 terrawatt hours

above its reference case level.

Because deregulation increases the competitive

pressures on electricity producers it is also

likely to have an impact on the choice of fuels

used in the generation sector and on fuel

procurement policies. In the current environ-

Figure 8: Impacts of deregulation on

electricity intensity, 2010

Relative to the reference case

1.75

1.50

1.25

1.00

0.75

0.50

0.25

%

Japan

Korea

Figure 9: Impacts of deregulation on

electricity consumption, 2010

Relative to the reference case

2.0

1.5

1.0

0.5

%

Japan

Korea

Chinese

Taipei

Chinese

Taipei

12


ABARE CONFERENCE PAPER 02.6

ment, coal fired electricity generation technologies

are the most cost effective.

In Japan, the competitiveness of coal is reinforced

by the removal of the requirement to

purchase high priced domestic coal. As a result,

the share of coal in Japan’s electricity fuel mix

at 2010 is almost 1 percentage point higher than

in the reference case. That is, coal is projected

to account for 22.8 per cent of Japan’s electricity

generation in 2010, following the implementation

of regulatory reform.

Figure 10: Impacts of deregulation on

thermal coal consumption, 2010

Relative to the reference case

10

8

6

4

2

%

Japan

Korea

Chinese

Taipei

Coal also increases its share of electricity generation

in Korea and Chinese Taipei, although to a smaller extent than in Japan. This is partly

because the relatively large increase in demand for coal from Japan has an upward impact

on world coal prices and limits the shift into coal in the other economies.

The combined impacts of the growth in economic output, structural shifts toward electricity

intensive activities and changes in the electricity fuel mix that follow deregulation

result in increased consumption of coal in each of the north east Asian economies relative

to the reference case (figure 10). And because these economies have no significant domestic

energy resources this translates into higher imports at 2010 relative to reference case

levels. Coal imports in north east Asia are projected to increase by around 12 million

tonnes relative to the reference case in 2010.

Climate change response policies

The imposition of more stringent environmental standards in coal production and use represents

the main down side to ABARE’s reference case coal consumption projections in the

period to 2010. Although the environmental agenda is broad, the implementation of international

policy responses to the threat of global climate change will be particularly relevant.

This is because coal accounts for a large share of greenhouse gas emissions generated by

human (anthropogenic) activity. Carbon dioxide emissions from fossil fuel combustion

are the major source of anthropogenic greenhouse gas emissions and coal is the most

carbon intensive fossil fuel. It is likely that over the next few decades, given the projected

economic growth in developing countries and their continued reliance on coal as a fuel

source, coal will contribute an even greater share of greenhouse gas emissions than at

present.

Under the Kyoto Protocol to the United Nations Framework Convention on Climate Change

(adopted in December 1997 but not yet entered into force) developed countries (listed in

Annex B to the protocol) agreed to reduce their aggregate emissions of greenhouse gases

to 5.2 per cent below the 1990 level over the period 2008–12. Individual country targets

13


ABARE CONFERENCE PAPER 02.6

were also negotiated. The protocol provides a framework only and negotiations to settle

the operating principles and guidelines in order to implement the protocol have continued

since then.

At the meeting of the parties in Bonn in July 2001, progress was made on a range of issues

including finance for developing countries, important elements of forest sinks, mechanisms

and compliance decisions, but other significant elements remain to be agreed.

Settling these potentially difficult outstanding points was the major task at the following

Conference of the parties (COP7) held in Marrakech in October–November 2001. These

issues were resolved in Marrakech and the agreement reached leaves the way open for

ratification of the protocol by many parties and for its potential entry into force.

The cost of meeting emission abatement commitments will depend to a large degree on

access to the Kyoto mechanisms — international emissions trading, joint implementation

and the clean development mechanism — and to carbon sinks. The less hampered the

operation of the Kyoto mechanisms and the greater the access to sinks, the greater the

flexibility available to countries in undertaking abatement and the lower the emission

penalty required to induce emission abatement to meet the Kyoto targets.

The climate change policy simulation that is presented here represents the outcomes on

sinks, the clean development mechanism and international emissions trading that emerged

from the agreement in Bonn. It is also assumed in the simulation that the United States

and Canada do not ratify the Kyoto Protocol and hence do not participate in an Annex B

emissions trading scheme or undertake emissions abatement other than the changes in

emissions intensity already included in the reference case. All other Annex B parties are

assumed to comply with their Kyoto targets by the first commitment period. In the simulation,

the price of emissions quota is equal to $48 a tonne at 2010 (in 2000 terms).

Additional details about the modeling can be found in Jakeman et al. (2001).

The results of the simulation indicate that the implementation of climate change policies

will have a contractionary impact on global coal consumption (figure 11). Among other

impacts, imposing an emissions penalty increases the consumer price of fossil fuel based

energy in emission abating countries and

leads to a reduction in coal consumption in

those countries.

Figure 11: Impacts of climate change

policies on coal consumption, 2010

Relative to the reference case

Conversely, fossil fuel prices in countries that

do not undertake emissions abatement are

projected to fall as the lower demand for coal

from countries with emission abatement policies

leads to a fall in world coal prices. This is

projected to lead to an increase in coal

consumption in nonabating countries.

However, this does not fully offset the

projected reduction in coal consumption in

%

–2

–4

–6

–8

–10

Annex B

excl. US and Canada

Non-Annex B

World

14


ABARE CONFERENCE PAPER 02.6

Figure 12: Impacts of climate change policies on coal consumption, by region, 2010,

reference case

%

–5

–10

–15

–20

–25

Australia

Japan

EU

Eastern

Europe

FSU

North

America

Developing

countries with emission abatement policies and there is a net contraction in global coal

consumption relative to the reference case.

In individual countries and regions, there are significant differences in the impacts on coal

consumption (figure 12). The relative outcomes depend on how each economy responds in three

areas — economic growth, fuel switching and the structural composition of output and trade.

One of the key impacts on coal consumption following the implementation of climate

change policies comes from fuel switching, particularly in the electricity sector, where

there are several alternative fuels. Because coal is the most carbon intensive fossil fuel,

the increase in its price is greater than for other fossil fuels. Under an emission penalty,

electricity generators and other energy users switch from coal to less emission intensive

fuels, including gas and renewables. The share of thermal (brown and black) coal in electricity

generation in Australia in 2010, for example, is projected to decline from 78 per

cent in the reference case to 74 per cent in the climate change policy simulation.

The extent of fuel switching in the electricity sector depends on the growth in electricity

demand, the importance of coal fired generation in the reference case and accessibility to

other fuels. Because Japan, for example, is less dependent on coal than Australia and its

projected growth in electricity consumption is lower, the extent of movement out of coal

into other less carbon intensive energy sources

is less pronounced. This explains to a large

extent the relatively lower contraction in coal

consumption in Japan than in Australia.

Reflecting the contraction in world coal

consumption, global coal trade also contracts

relative to the reference case at 2010 (figure

13). An expansion in coal imports by countries

that do not undertake emissions abatement is

insufficient to offset the contraction in imports

by countries that implement emission abatement

policies.

Figure 13: Impacts of climate change

policies on coal imports, by region, 2010

Relative to the reference case

1

%

–1

–2

–3

–4

–5

–6

–7

Annex B

excl. US and Canada

Non-Annex B

World

15


ABARE CONFERENCE PAPER 02.6

Conclusions

The main findings of the study on which this paper is based point to a positive outlook for

global coal markets over the period to 2010. Coal consumption is expected to expand steadily

and coal is projected to maintain its share of the world fuel mix. Strong growth in developing

Asian economies will be a key determinant of this trend but renewed interest in coal fired

electricity generation in some developed economies will also be important.

Beyond the reference case framework, there are several policy developments that are likely

to have a strong bearing on the long term outlook for coal. The introduction or enhancement

of competition in electricity markets, for example, can be expected to lead to higher thermal

coal consumption in countries where the cost of coal fired electricity generation is competitive

with alternative fuels and technologies. Environmental issues, especially the implementation

of climate change response policies, could challenge the growth in coal consumption by

increasing the cost of using coal compared with less greenhouse gas emission intensive energies.

Notwithstanding this, there will be significant opportunities for competitive coal producers

to expand their output and exports, provided that investment in production, transport

and port capacities is maintained. Traditionally dominant suppliers of coal to the world

market such as Australia may be increasingly challenged over the next decade by competition

from emerging producers such as China and Indonesia. More intense competition,

especially in thermal coal markets, highlights the importance of ongoing productivity

improvements at all stages of the coal supply chain.

References

Fairhead, L., Schneider, K. and Ye, Q. 2001, Deregulating Electricity Supply Industries

in North East Asia: Impacts on Energy Markets, ABARE Current Issues 01.8, Canberra.

IEA (International Energy Agency) 2001, Coal Information 2001, Organisation for

Economic Cooperation and Development, Paris.

IMF (International Monetary Fund) 2000, International Financial Statistics, Washington DC.

Jakeman, J., Heyhoe, E., Pant, H., Woffenden, K. and Fisher, B.S. 2001, The Kyoto

Protocol: economic impacts under the terms of the Bonn agreement, ABARE conference

paper 2001.28 presented at the symposium ‘Long Term Carbon and Energy

Management: Issues and Approaches’, convened by the International Petroleum Industry

Environmental Conservation Association, Cambridge, Massachusetts, 15–16 October.

Mélanie, J., Curtotti, R., Saunders, M., Schneider, K., Fairhead, L. and Ye, Q. 2002, Global

Coal Markets: Prospects to 2010, ABARE Research Report 02.2, Canberra.

Sinton, J.E. and Fridley, D.G. 2000, ‘What goes up: recent trends in China’s energy

consumption’, Energy Policy, vol. 28, pp. 671–87.

16


COAL DEMAND AND SUPPLY

OUTLOOK

Mr Bai Ran

Director General

Department of International Cooperation

China National Coal Association

PR China


ABSTRACT

Brief Introduction on the Coal Supply & Demand Relations in China

China has long been the largest coal producer and consumer in the world. From the early to the

late 1990s, a severe problem of coal supply far surpassing the demand has popped up. With

measures taken for coal mine downsizing and general output control since 2001, China’s coal

market has basically been balanced, but partially still unstable. Economy is expected to get on a

sustainable increase in the coming decades, and this will bring about the increase of the demand

for energy and coal. With China entering WTO, coal provision ability of will be enhanced, and

the domestic coal supply and coal demand relations shall be balanced through both the

international and domestic market.


On Coordination of Coal

Supply & Demand in China

Bai Ran

March 4, 2002


Contents

• Preface

• I : Excessive coal supply from early 1990s to mid and

late 1990s

• II: A basically balanced but partially intense coal

supply by the end of 1990s and 2001 in China

• III: Coordinated coal supply and demand in the

coming decades

• IV : Conclusions


Preface: The Coordination of Coal Supply

& Demand in China is very important

• Coal is the most important primary energy and

industrial chemical material in China.

Coordination of supply and demand is not only

important in the Chinese coal market, but also in

the world, because China’s coal output and

consumption accounts for over one fourth in the

world’s coal market respectively.


The relationship has undergone

big changes

• Since 1990s, coal market in China has

undergone a big change from excessive coal

supply to a basically even supply to a little

insufficient supply.


I. Excessive coal supply from early 1990s to

mid and late 1990s

• Express: The three key indexes

• 1. The average raw coal price at the pit-mouth has been

lowed by 15.7% from 1997 to 1999.

• 2. Payment delayed has been on a increase in 1990s. By

the end of 1999, total payment delayed had reached 33

billion Yuan RMB, which equaled to 4 billion USD.

• 3. Coal storage has been on an increase. By the end of

1999, the national social coal storage had reached 180

million tons, with coal mine storage reaching 85 million

tons.


The main reasons for excessive coal supply are as

follows:

• 1. The growth of coal output from small mines was too fast. A great

number of small township and village coal mines were set up in the

middle and late 1990s. The number of mines increased from about

10,000 in 1980 to 80,000 in 1997. The coal output from small mines

increased from 110 million tons in 1980 to 570 million tons in 1997.

The increase of national coal output in this period was 750 million tons,

while that from small mines was 500 million tons, an annual increase

of 32 million tons.


Among coal output from three categories of mines, i.e. stateowned

key coal mines, local government controlled stateowned

coal mines and township and village coal mines, the

percentage of coal from township and village coal mines

accounted for more than 40%.

2. The slow increase of coal export aggravated the situation

of excessive coal supply.


II. A basically balanced but locally intense

coal supply situation by the end of 1990s and 2001

in China

• See it from the following facts:

• 1. A rise in coal price. The average coal price of stateowned

pit-mouth mines increased by 7.5% as compared

with that in 2000. The coal price in major coal consuming

cities were on the rise generally.


• 2. A large decrease of coal stock. The national coal

stock on hand was 120 million tons by the end of 2001, a

decrease of 85 million tons, or 42.5%, as compared with

that in 1997. The coal stock in mines reduced by 25

million tons, or 47.4% by the end of 2001, comparing with

that in 1997.

• 3. Decrease of arrearages. Comparing with 2000, the

revenue from sales of salable coal in the state-owned key

coal mines increased by 13.3 billion RMB in 2001. The

arrearages reduced by 14% by the end of 2001, as against

that by the end of 2000.


The shift excessive coal supply to a basically

balanced but locally intense situation is due to three

factors:

• 1. To decrease in large quantity coal supply to the market

and to continue to implement the policy of controlling the

national coal output and closing of mines. In December

1998 the State Counsel issued a circular entitled " Closing

illegal and irrationally located coal mines". The general

requirement was to control the total coal output and to

close mines. It requested to close 25,800 mines and to

reduce 250 million tons of coal output by the end of 1999.

And the national coal output in 1999 was targeted at 1.1

billion tons. This policy continued in 2000 and 2001.


• In 2001, the state implemented a policy of regulating small

mines with a purpose to improve mine safety. More than

10,000 small mines were closed. As a result, coal from

small mines reduced considerably. The State Council sent

out two circulars, one in June and one in September in

2001. It was requested to cease production of the flowing

four kinds of mines for regulation.

• From 1998 to 2001, 50,000 small mines were closed in

total. The national raw coal output decreased year by year

as against that in 1997.


Comparison of percentage of raw coal

output in three kinds of coal mines in China

between 2001 and 1997

1997

2001

43%

40%

23%

17%

21%

56%

SOKM LGOM TAVM

SOKM LGOM TAVM


• 2. Steady increase of national economy. Increase of

production of coal-consuming industries.The increase of

GDP in 2001 was over 7%. This certainly resulted in

increased demand for coal. The production of major coalconsuming

industries increased in 2001 as against those in

2000, such as electricity from coal-fired power plant, steel,

cement, slab glasses and nitrogen fertilizer. It was

preliminarily estimated that the demand for coal from four

major industries, like power, metallurgical, building

material and fertilizer industries will increase by about 35

million tons in 2001 as compared with those in 2000..


• 3. Considerable increase of coal export. In 2001China

exported 85.90 million tons of coal, an increase about 27

millions, or 46% as against that in 2000. China became the

2 nd largest coal exporter in the world. This resulted from

proximity to some Asian coal import countries, the policy

of encouraging coal export from the state and improved

management of coal export enterprises.


III .

Coordinated coal supply and demand in

the coming decades.

• The 10 th Five-Year-Plan is a very important period in

China. GDP will continue to increase by over 7% during

this period. So, this will lead to more demand for energy

for it has long time been the major primary resources in

China.


• Coal in China is mainly for domestic market. Coal

resources in China can fully satisfy the need for coal in the

near future. With structural adjustment of coal mining

industry in China, the production capacity of the stateowned

large-sized and middle-sized mines will be

enhanced. In the near future, the state will put more

investment to newly built state-owned key coal mines. At

the same time technical transformation will be carried out

in the existing mines. As to small mines, after closure of

illegal and miss-placed mines and rectification of mine

safety, the average scale of small mines will expand.

Stability of coal supply will be improved.


• China has already joined WTO, the international coal

market regulating factors will become more and more

important in coordinating coal supply and demand in the

domestic market. In the coming period, China coal market

will keep the framework of exporting coal in the northern

major coal producing provinces and importing coal to the

southern, especially coastal provinces where coal is in

shortage.


IV.

Conclusions

• 1. China is the largest coal producer and

consumer in the world. In the recent years the

relationship between coal supply and demand in

China has changed constantly.

• 2. From early to mid 1990s, coal supply far

surpassed demand in China. This mainly resulted

from the rapid growth of coal output from small

mines and slow increase of coal export.


• 3. In 2000, a balanced yet slightly insufficient

coal supply appeared in China. This was due to

policies for control of production and mine

downsizing; policies of improving mine safety in

small mines; and policy for encouragement of coal

export and increased demand.

• 4. In the coming period China will keep a trend of

constant and steady growth of economy, which in

turn, will increase demand for coal. The coal

supply capacity will also increase. With China's

entry into WTO, China will adjust coal supply and

demand in domestic market by making use of coal

resources and markets at home and abroad.


SESSION 2:

Coal in Optimum Energy Mix

(Security and Environment)

Chair: Mr John Karas

Manager, Coal Industries Section

Department of Industry, Tourism and Resources (ITR)

Australia


NEW ROLE FOR COAL

AND CCTs IN ENERGY

SECURITY IN APEC

Dr Charles Johnson

Energy Consultant

Asian Energy Strategies, USA


Introduction

This paper reviews the evolution of environmental and energy security issues related to coal,

and suggests a possible solution to the policy makers dilemma in dealing with conflicting goals. After

the first oil crisis in 1973, coal was quickly identified as an important option to increase energy

security. Policies were implemented in most APEC economies that encouraged coal use for power

generation. As concerns over oil supply shortages waned in the mid-1980s, policy makers shifted

more attention to the environmental aspects of fossil-fuel use. With respect to coal, the introduction

of clean coal technologies (CCTs) has allowed coal to achieve high levels of environmental

performance at the local and regional levels. However, global warming concerns and global

agreements to restrict greenhouse gas (GHG) emissions threaten coal’s future growth prospects.

This paper suggests that the external costs of energy security are not reflected in the market prices

of energy options. The paper will illustrate that when the external costs of energy are taken into

account, the political ranking of coal is improved.

Environmental Challenges to Coal

Local and Regional Environmental Issues

There is a reputable body of research indicating that health-related environmental costs of

burning fossil-fuels produces tens of billions of US dollars in health-related costs every year. 2 Coal

is the leading cause of airborne particulates and SO 2 pollution among APEC economies. Available

commercially proven CCTs can greatly reduce the damages caused by coal if installed and operated

properly. The major health-related pollutants of concern are particulates, SO 2 and NO X . 3 Costs of

controlling these harmful emissions from coal-fired power plants is typically no more than

US$0.01/kWh in most APEC economies. 4 The reasons for the high health costs of burning coal are

primarily legislative and enforcement issues and not a technology issue. Competitive CCTs exist

to control harmful coal-related emissions, but these technologies have yet to be fully adopted among

2 The World Bank has published numerous reports that examine the health damaging impacts of fossil-energy

use, including: World Bank, 1997, Clear Water, Blue Skies. Also, see the chapter: Energy, the Environment and

Health in the 2000 World Energy Assessment; United Nations Development Programme, United Nations

Department of Economic and Social Affairs and the World Energy Council.

3 More recently, mercury emissions have also become a pollutant of concern in some APEC economies.

4 Japan is an exception where stringent environmental regulations and procedures add substantially more than

US$0.01/kWh to coal-fired power plants.

2


APEC economies. The progress among APEC economies in enforcing tighter environmental

regulations suggest health-related costs of coal have fallen dramatically in recent years, and this trend

is expected to continue.

Global Environmental Issue: GHGs

A far more difficult and costly challenge is how to control GHG emissions that contribute to

global warming. In 1992 the United Nations Framework Convention on Climate Change was

signed by more than 150 nations and committed all parties to: “take climate change considerations

into account, to the extent feasible, in their relevant social, economic and environmental policies and

actions…” (article 4.1f)

Subsequent negotiations led to the signing of the 1997 Kyoto Protocol that committed

industrial and former Eastern bloc nations to reducing GHG emissions by an average of 5.2 percent

below 1990 levels by 2008-2012 period. The agreement includes several flexible mechanisms to

allow nations to achieve their targets -- most importantly, emissions trading and the Clean

Development Mechanism (CDM).

The unfortunate withdrawal in March 2001 of the United States from the UN Climate

Change negotiations appears to have galvanized 178 other nations into approving the terms and

mechanisms for implementing the Kyoto Protocol. The rest of the world has now agreed to move

forward with ratifying the Kyoto Protocol without participation of the United States; and there is a

moderate chance that the Kyoto Protocol will come into force without the US participation. Most

nations will need to participate actively in emissions trading to achieve their GHG targets by 2008-

2012. From a global perspective, without participation of the largest contributor of GHGs (United

States), achieving meaningful global GHG reductions will be exceedingly difficult.

The central problem for the United States appears to be the expected high economic costs

of complying with the GHG commitments within the timetable agreed at Kyoto. However, as this

author has said in previous papers, ratification of the Kyoto Protocol is not critical to reducing

GHGs. 5 On February 14, 2002, the President Bush announced the government’s plan to reduce

GHG emissions based on a voluntary approach tied to economic incentives for business. The

announced goal is to achieve an 18 percent reduction in GHG intensity over 10 years – equal to

roughly a 4.5 percent reduction in GHG emissions over the period. The US plan includes an

emissions trading system for US industry. But the goal of approximately a 2 percent annual

5 See the author’s paper, Impacts of GHG Constraints on the Long-term Competitive Position of Coal in Asia, in

the ong>Proceedingsong> of the Sixth APEC Coal Flow Seminar, March 2000.

3


eduction in GHG intensity is only slightly better than the historical decline of 1.5 percent per year.

In order to make a meaningful contribution to reducing CO 2 emissions, the US will need to commit

to a more aggressive CO 2 reduction plan in the future; and hopefully the US government will

reconsider its decision to withdraw from the important UN Climate Change agreements.

The largest GHG reductions in any economy over the past five years has been in PR China

where CO 2 emissions fell by 15 percent between 1996 and 2000 primarily due to more than a 20

percent decline in coal consumption. Most impressive was China’s ability to reduce GHG emissions

while also increasing the GDP by 35 percent over the same period. China’s reduction in CO 2

emissions was not due to climate change commitments, but the result of changes underway in

China’s internal economy, including deregulation of industry and energy prices and removal of

energy subsidies. China’s example, illustrates the importance of deregulation and promotion

of market-based economic growth in conjunction with sound environmental policies to

achieve less carbon intensive growth.

Implementations to Coal of GHG Constraints

Restrictions on GHG emissions among some APEC economies appear likely before 2010.

Coal ranks high (perhaps highest) on the list of potential targets for reducing GHG emissions in the

short and medium terms. Coal accounts for the highest emissions of CO 2 per unit of energy of the

fuel options, plus coal is widely believed by the public to be a highly polluting fuel.

It remains uncertain how well coal will fare in an increasingly carbon-constrained world,

unless there are other mitigating factors, such as development of low-cost options to capture CO 2

emissions from coal and/or a much heavier weight given to energy security. Clean coal technologies

are clearly an essential element in both changing the public perceptions of coal, and in enhancing the

environmental performance of coal. Proven competitive CCTs can increase energy efficiencies by

10-25 percent over the next decade. Technologies under development may increase CCT

efficiencies by perhaps 25-35 percent, but these CCTs have yet to be proven on a commercial

scale.

But in the longer term (by 2020) governments are likely to require much greater reductions

in CO 2 emissions than CCT efficiency gains can achieve. Recovery and sequestration of CO 2 from

fossil-fueled power plants appears to be essential to achieving meaningful long-term reductions of

GHG emissions. The estimated costs of CO 2 recovery and sequestration are falling, and still

4


speculative, but might fall in the US$0.02 cents/kWh range. 6 It is impossible to predict when

commercial CO 2 recovery and sequestration systems will be widely used in coal-fired power plants.

However, this author is cautiously optimistic that coal will remain competitive in a world where CO 2

recovery and sequestration is mandatory for all fossil-fueled plants.

Rethinking Energy Security

Brief History of Energy Security

Energy security became a hot policy issue following the oil shocks in 1973 and 1979. The

focus of policy makers in major oil importing economies was how to deal with a strong OPEC that

controls a sufficient share of world oil supplies to influence crude oil prices. Strategies adopted by

governments included: (i) establishing state oil companies, (ii) encouraging domestic energy

production, (iii) promoting alternative energy sources, (iv) establishing petroleum stockpiles, and (v)

energy conservation. Shortly after the 1973 oil crisis, the United States launched Project

Independence 7 , which was aimed at reducing its oil import dependence. Major efforts were made

to expand domestic energy production, including liquids from oil-shale and coal, plus automobile

mileage efficiency standards were introduced.

Enthusiasm in most economies for strategies to diversify away from OPEC oil was to

gradually fade due to:

i) falling crude oil prices in the mid-1980s,

ii) the high costs of most state energy companies that became a drain on

government budgets, 8

iii) higher than expected costs of new energy options, and

iv) increased reliance on market liberalization to promote greater competition

among energy options and companies.

In 1990, Iraq invaded Kuwait, threatening the stability of the Middle East and oil supplies

from the region. A multinational military response, led by the United States, pushed Iraq out of

Kuwait. There were only temporary impacts on oil prices, and by the late-1990s, action on energy

security issues had declined to a low level. The short-term spike in crude oil prices in 2000-2001

6 Numerous studies are underway in a number of APEC economies on the recovery of CO 2 from coal-fired power

plants. A useful recent paper is: Dale Simbeck, 2001, CO 2 Mitigation Economics for Existing Coal-Fired Power

Plants, presented at the Eighteenth Annual International Pittsburgh Coal Conference.

7 The Achilles heel of Project Independence was too much attention to the technical feasibility of energy

independence and too little attention to the power of global market forces on energy supplies and prices.

8 Malaysia’s Petronas is reportedly among the most successful state oil and gas companies.

5


enewed interest in energy security issues, and resulted in numerous energy security meetings under

the APEC umbrella. The primary focus was on reviewing options to reduce dependence on oil and

oil stockpile strategies. However, before governments could take any substantive action, the

combination of market forces and OPEC were bringing oil prices down to more reasonable levels to

importing nations. But September 11, 2001 may have been the catalyst that will change the thinking

about energy security forever.

Terrorist Costs to Energy Security

Hopefully there will never be an attack on the energy system of any APEC economy on the

order of the attacks of September 11 th , 2001. However, there exist terrorist groups that are

examining the vulnerabilities of energy systems within APEC economies. Both nuclear power plants

and large hydroelectric facilities are known to be on the list of possible targets. It is prudent for

governments to assume that any large energy facility could be a terrorist target.

The vulnerability of energy systems varies among economies. Economies with heavy

dependence on domestic energy supplies are at less risk than large oil and gas importing economies.

The following provides the author’s brief views of energy vulnerabilities:

1) Nuclear Power

There are three key risks to nuclear power plants: (i) a serious accident at an operating plant

resulting in a major release of radiation; (ii) the diversion of nuclear materials to terrorist groups or

nations that want to produce nuclear weapons, and (iii) a terrorist attack on a nuclear facility. Of

these three risks, the largest threat may be a terrorist attack on a large nuclear facility. Most nuclear

risk experts believe the probability of a successful attack on a nuclear facility is very low. However,

in light of September 11, 2001, a thorough re-examination of these risks is essential.

The dilemma for governments is that nuclear power is the best large-scale option for

reducing GHGs from power plants. In addition, nuclear power is viewed by some APEC

governments as an important element of energy diversification to enhance energy security. The

author’s view is that nuclear power is an unacceptable option in the energy mix because of the

potential devastating implications of the three risks listed above, and its unfavorable commercial

economics. In commercial terms, nuclear power is not competitive with other energy options when

all costs are fully accounted for in the analysis – particularly, direct and indirect government

subsidies, and the costs of nuclear waste storage over several hundred years.

6


2) Oil

The backbone of world’s transport systems is oil, and diversification away from the gasoline

engine will take several decades under business-as-usual scenarios. Domestic oil supplies appear to

have less risk from terrorist attacks than imported oil from the Middle East. Most APEC economies

are deficient in oil reserves, and increasingly dependent on imported oil, mostly from the Middle

East. But Middle East oil imports carries high external costs not reflected in the market price of oil.

These costs to major oil-importing economies include a military presence in the Middle East. Most

independent oil analysts rank possible political crises in the Middle East as the number one energy

security risk in the world.

The Middle East holds over 60 percent of the world’s proven oil reserves; and there is no

realistic near-term option for diversification away from Middle East oil. Even in the longer-term,

diversification away from Middle East oil may be costly. Assuming immediate diversification away

from Middle East oil was practical, it should be done gradually to allow Middle East economies to

diversify their economies. Economic stability for the people of the Middle East should be in the

interests of all economies, regardless of the level of oil import dependence.

Economies of scale have resulted in larger supertankers and refineries that unfortunately are

more vulnerable to terrorist attacks. Pipelines are also vulnerable, although in most cases, the

economic and environmental risks appear manageable, and pipelines can be quickly repaired.

In addition, oil is a major contributor to global warming. Oil is already the world’s largest

source of man-made GHG emissions, and under business-as-usual scenarios, oil consumption is

projected to increase more rapidly than coal. However, oil is used inefficiently in automobiles

compared to the potential of a new generation of cars that could be introduced under the right policy

framework. For example, hybrid-electric cars are already being introduced that can increase gas

mileage by 50 to 100 percent. A rethinking of the entire approach to transportation systems in

APEC economies is essential -- from cars to mass transit systems.

2) Natural gas

Where available, natural gas became the fuel of choice for much of the new electricity

generation capacity in the 1990s. Advances in electricity generation efficiencies and falling costs of

combined cycle gas-turbine plants enhanced the competitive position of natural gas over coal where

pipeline supplies are available. However, providing natural gas to most Asian APEC economies

7


equires massive investments in regional natural gas pipelines and LNG facilities. The immense size

of such pipeline investments has prevented the development of an Asia-wide pipeline distribution

system. The trend is to continue with incremental expansions of pipeline infrastructure among Asian

APEC economies (P.R. China, Indonesia, Malaysia, Thailand, and Vietnam).

Most governments prefer natural gas to coal because of its cleaner burning characteristics

than coal. However, the GHG claims for natural gas are often exaggerated, because when methane

losses in production and distribution are fully accounted for, the GHG advantage held by natural gas

over coal is substantially reduced.

3) Coal

Coal has three compelling reasons why it is important to most APEC economies: (i) coal

reserves within APEC economies far exceed reserves of oil and gas; (ii) coal can be delivered to

power plants at the lowest cost of any fossil-fuel; and (iii) coal supplies come from some of the most

politically stable economies in the world.

Offsetting these advantages are the costs of controlling harmful emissions from the

combustion of coal. As previously discussed, the local and regional health damaging pollutants of

coal can be controlled using commercially available control technologies at about US$0.01/kWh.

The challenge in meeting future GHG constraints is formidable, but not insurmountable, given

sustained research on improving CCTs and CO 2 recovery and sequestration.

Possible risks to both civilian populations and the environment from terrorist attacks on coal

facilities are far less than on nuclear, oil and natural gas facilities. In addition, lost coal capacity can

be rapidly replaced. The reassessment of energy security risks is likely to improve coal’s

importance to energy security and the energy mix of major oil importing economies.

4) Renewable Energy

Renewable energy (wind, solar, hydro and biomass) is very popular among both environmental

groups and most governments. Many analysts believe renewable energy has a critical longer-term

role in reducing GHG emissions and in enhancing energy security. Locally, renewable energy

systems are already an important and competitive source of energy in niche markets. However,

nationally and globally renewable energy represents a small share of the energy mix of major

economies, and is projected to play a minor role over at least the next fifteen years.

8


Energy Planning Dilemma

1) Strategies to minimize GHG emissions favor increases in nuclear power, natural gas and

large hydropower, and decreases of coal in the energy mix.

2) Strategies to minimize energy security risks favor an expanded role for coal in the energy

mix.

The policy dilemma is that achieving major reductions in GHG emissions is unlikely to be

compatible with maximizing energy security. Simulation modeling can estimate the lowest costs

for simultaneously achieving both goals if one knows the input variables. While there are

estimates of plausible costs of achieving GHG targets in most APEC economies, estimates of the

risks and costs related to possible terrorist attacks on the energy system are more problematic.

An attempt has been made to show plausible rankings of energy options when both

GHG and energy security costs are being weighed. These rankings are the subjective

estimates of the author for a large oil and gas importing economy. Each APEC economy will

have somewhat different weights, depending on the specific characteristics of the energy system

and their environmental policies.

Figure 1 shows schematically the location of the five major energy options, with GHG

Costs on the vertical axis and energy security costs on the horizontal axis. The economy is

assumed to be heavily dependant on oil and natural gas imports. In the case of coal, the degree

of import dependence does not substantially increase energy security risks in most cases. It is

assumed that all new coal plants will use modern CCTs and advanced emissions control

equipment. As shown in Figure 1:

• Coal has the highest GHG costs but low energy security costs

• Renewable energy has both low GHG and energy security costs 9

• Natural gas has medium GHG and energy security costs

• Oil has medium-high GHG and energy security costs

• Nuclear power has low GHG but high energy security costs

9 Renewable energy includes: wind, solar, geothermal, and small to medium hydroelectric and biomass.

9


Difficult policy choices require government policy makers to weigh the tradeoffs between

various risks and achieve a politically acceptable energy mix. Figures 2 and 3 illustrate the

political risk weightings for perceived low and high terrorist risk cases in a large economy dependent

on large oil and natural gas imports. Coal can come from either domestic or imported sources. 10

The vertical axis shows subjectively the combined economic costs of GHG and energy security to

the economy. The horizontal axis shows subjectively the relative political risk ranking of energy

supply options. 11 As shown in Figure 2, for the low terrorist risk scenario, coal is the least

favored, followed by nuclear power, oil, natural gas and renewable energy. However, in the high

terrorist risk scenario shown in Figure 3, coal becomes the second most favored energy option

after renewable energy. Some governments will give a heavier weight to imported natural gas;

therefore shifting coal to third place behind renewable energy and natural gas.

It is recognized that many in the environmental community will not agree with giving coal a

high priority ranking under any circumstances. However, the costs associated with terrorism can be

high, and when fully included in the analysis will enhance coal’s political ranking in the directions

shown in the figures.

Perhaps the best example of the costs related to the Middle East oil is for the United States.

If all direct and indirect costs related to ensuring stable Middle East oil supplies were included in

the price of imported oil from the Middle East, the real cost of a barrel of imported oil would

increase by perhaps 50 percent or more. 12 These costs will vary between APEC economies

depending on each economy’s exposure to these risks and associated costs. 13

The Soft Side of Energy Security

Energy security is not just the technical and economic aspects of establishing oil stockpiles

and contingency plans to respond to any interruption in oil supplies. The success of international

energy security plans will depend on the depth of commitment of cooperating governments and the

international oil industry. Too little attention appears to be given to this soft side of energy security

(i.e., building strong and trusted relationships between governments and between governments and

the energy industry).

Part of the problem is the simple failure to listen to and understand the

10 There is only a small increase in energy security risk for imported coal over domestic production.

11 It is assumed that energy conservation is an important element of any of the energy supply scenarios.

12 There is no accurate method to separate risks and costs related to energy issues from costs related to other

factors, such as political considerations.

13 If the US were to reduce or withdraw from its efforts to ensure stable oil supplies from the Middle East, then the

risks and costs would increase to other economies dependent on Middle East oil imports.

10


viewpoints of other governments and other energy companies. Too often, meetings between

governments, and between industry and governments are dominated by talking and lecturing to the

other side, but not listening. We talk, but do we always listen and try to understand differing

views Giving more attention to listening and understanding the views, political differences, cultures

and religions of others will surely promote greater energy security.

APEC CFE provides an excellent forum for doing much more than exchanging technical

information among members. It is an important opportunity to learn more about the people and

cultures in various APEC economies. What other forum meets in so many different APEC

economies and is freely open to anyone to participate The strength of international investments in

energy and in energy security arrangements may be as much dependant on building lasting

relationships between the people of different economies, as in the written agreements and technology

transfers.

Conclusions

This paper reviewed local, regional and global aspects of environmental issues impacting on

coal, and the role and limitations of CCTs in addressing these issues. The problems of meeting local

and regional health damaging impacts of coal are mostly due to the lack of enforcement of adequate

environmental legislation, and not the lack of suitable pollution control equipment. Among fossilenergy

options, coal faces the most formidable challenges in meeting future GHG constraints.

However, given an adequate R&D commitment, the prospects are promising for the eventual

commercial recovery and sequestration of CO 2 at acceptable costs.

Historically, energy security has focused on oil-related security, particularly related to

Middle East oil supplies. However, post-September 11, 2001, energy security considerations need

to place greater weight on the risks and costs of terrorist attacks on energy systems. The author’s

subjective weightings of environmental and energy security costs suggest that coal and CCTs would

have a much higher political ranking among energy supply options under conditions of perceived high

terrorist risk. It follows that a critical rethinking of the role of coal and CCTs is needed in light of the

new dimensions of energy security.

Finally, energy and environmental security is dependant in large part on building solid

relationships and trust between governments, as well as between governments and foreign investors

in energy. In addition to APEC CFE’s role in exchanging technical information, an important role is

11


to build better relations, understanding and respect between governments and between governments

and investors in energy.

12


Rethinking the Role of Coal and CCTs

in Energy Security in APEC

Economies

Charles J. Johnson

8 th APEC Coal Flow Seminar

9 th APEC Clean Fossil Energy Technical Seminar

4 th APEC Coal TILF Workshop

Kuala Lumpur, Malaysia

Monday 4 March to Friday 8 March 2002


Evolution of environmental and energy

security issues related to coal, and a

possible solution to the policy makers

dilemma in dealing with conflicting goals


Local and Regional

Environmental Issues

1) Fossil-Fuels account for US$10s of billions in

health related costs every year

2) Leading pollutants: particulates, SO 2 and NO X

3) Available technologies can control for

~US$0.01

4) Issue is legislative and enforcement and not

technology

5) Health-related costs falling within APEC


Global Environmental Issue

1) 1992 United Nations Framework Convention on

Climate Change:

“take climate change considerations into account, to the

extent feasible, in their relevant social, economic and

environmental policies and actions…”

2) 1997 Kyoto Protocol committed indusrilized and

former eastern bloc nations to reducing GHGs

3) Flexible mechanisms: emissions trading and

CDM

4) 2001 US withdrawl galvanized 178 nations to

approve


Recent US announcement of a voluntary

market-driven approach to reduce GHG

is a first step toward, hopefully

substantive commitments and a return

to UN Climate Change agreements


1 st Place for total GHG

reductions over the 1996-2000

period goes to PR China


China illustrates that achieving

less carbon intensive growth is

facilitated by:

deregulation and promotion of

market-based economic growth in

conjunction with strengthening

environmental policies


Reductions in CO 2 emissions from CCT

efficiency gains are unlikely to meet

increasingly stringent requirements for

CO 2 reductions in the longer term

In the longer term, CO 2 recovery and

sequestration appears promising – with

speculative costs in the US$0.02/kWh

range


OPEC successes in hiking crude oil prices

in 1973 and 1979 resulted in oil

importing economies:

1) Establishing state oil companies

2) Encouraging domestic energy

production

3) Promoting alternative energy sources

4) Establishing petroleum stockpiles

5) Energy conservation


Enthusiasm to diversify away from

Middle East oil declined due to:

1) Falling crude oil prices in the mid-1980s

2) High costs of state energy companies

3) High costs of energy alternatives

4) Increased emphasis on open-markets

and competition to improve energy

security


Rethinking Energy

security after

September 11, 2001


Potential energy security

issues in primary energy

supplies:

1) Nuclear power

2) Oil

3) Natural Gas

4) Coal

5) Renewable Energy


Energy Planning Dilemma: How to

achieve both GHG reductions and

energy security:

‣ More nuclear power, natural gas and

large hydro, and less coal produces

lower GHG emissions

‣ More coal, and less nuclear, large hydro

and and imported oil enhances energy

security


High3

Greenhouse Gas Costs

2

1

0

Low

Coal

Oil

Gas

Renewables

Nuclear

0 1 2 3

Energy Security Costs

Energy Security vs. GHG Costs

High


High6

5

Coal

Economic Costs to

Economy

4

3

2

1

Nuclear

Oil

Gas

Renewables

Low0

High

0 1 2 3 4 5 6

Political Ranking

Ranking of Energy Options for Low Terriost Risk


6

High

5

Nuclear

Economic Costs to

Economy

4

3

2

1

Oil

Gas

Coal

Renewables

0

Low

0 1 2 3 4 5 6

Political Ranking

Rankings of Energy Options for High Terriost Risk

High


Soft Side to Enhancing

Energy Security

More attention needed in building strong

and trusted relationships between

governments and also between

governments and energy companies

More listening and understanding of

different viewpoints and cultures can

enhance real energy security


CONCLUSIONS:

1) CCTs can control local and regional health-damaging

pollutants from coal

2) In the longer term, CO2 recovery and sequestration

will be essential and is likely to be economic

3) Historically energy security’s main focus has been to

ensure oil supplies from the Middle East

4) Terrorist threats to energy systems are real, and

improve the “political ranking” of coal

5) Energy security is enhanced by technical exchanges,

and building better relations, understanding and

respect – goals that are consistent with APEC


POWER INDUSTRIES

IN KOREA

Dr Chang-Seob Kim

Chief of Climate Change Policy Team

Korea Energy Management Corporation

Korea


The Restructuring of The Electricity Industry in KOREA

DR CHANG-SEOB KIM

CHIEF OF CLIMATE CHANGE POLICY TEAM

KOREA ENERGY MANAGEMENT CORPORATION

KOREA

In the economic sense of the electricity industry, the view of line-bound energy industries as

"natural monopolies" has changed considerably during recent years upon the perception that each

of the industries could be seen as a combination of different functions. The natural monopoly

perception for each function has been reassessed, resulting frequently in transportation functions

such as transmission, distribution and dispatch remaining as natural monopolies while other

functions such as generation, wholesale and retail sales, metering, billing etc. have become

candidates for competitive opportunity. This new theoretical paradigm has stirred restructuring

and deregulation of line-bound energy industries in a number of economies with the most

prominent examples being the UK (Electricity Act of 1989) and Norway (Electricity Act of

1990) with other economies such as the USA (Energy Policy Act of 1992) and Sweden

(Competitive Electricity Market Bill of 1992).

In the past, the Korea Electric Power Corporation (KEPCO) assumed electricity supply

obligations with regulated electricity rates and monopolized the entire electricity supply industry,

including generation, transmission and distribution. In 2000, the KEPCO, comprising 92% of the

national installed generation capacity, produced 96% of national electricity production. A small

number of IPPs (Independent Power Producers), possessing Power Purchase Agreements (PPAs)

with the KEPCO, sold their output to the KEPCO, and the entire industry including electricity

rates became regulated by the Government. Customers didn’t have any rights to choose their

electricity suppliers and new entry into the industry was either regulated or prohibited at this

stage.

K E P C O

Generation

IPPs

Transmission

Distribution

Customers

Fig. 1 Integrated Electrical Utility of KEPCO

The current electricity market, which began operation on April 2, 2001, is referred to as the first

stage of restructuring and the Generation Competition Market. In this phase, multiple GenCos,

one (1) transmission/distribution company (KEPCO), and several IPPs exist in the market. The

transmission and distribution sectors remain as part of the KEPCO. The six (6) GenCos,

excluding the one (1) known as the Hydro Nuclear GenCo, are of similar size and mix in terms

of generating facilities. This ensures fair competition among all GenCos throughout the

marketplace. One of the five GenCos will be privatized at some point in 2002, although which

one has not yet been determined.


The Generation Competition market is being operated based on a set of Coat Based Pool (CBP)

Rules. In this market, the KPX determines the System Marginal Price (SMP) using generation

offers integrating the available capacity of generator’s as well as cost-based energy prices. At

this stage, GenCos and IPPs compete in the generation pool with bidding available capacity and

regulated cost-based energy prices while the KPX determines System Marginal Prices (SMP).

Fig. 2 Generation competition market

The wholesale electricity market, where generation companies and suppliers trade electricity, is

scheduled to begin in 2003. This stage introduces a Two Way Bidding Pool (TWBP) in which

the demand-side of the market will compete for supplies. To facilitate this, the distribution and

supply business elements will be separated from the KEPCO during 2002 and established as

subsidiary companies (Distribution and Retail Companies) promoting wholesale supply

competition. The principal buyers in the wholesale market will be distribution and retail

companies. The basic concept of the TWBP is to establish prices through the competitive

bidding of both generation and demand. However, in the initial stage of the TWBP based

wholesale competition market, demand side participation will occur in a manner customers’

responding to such as market pricing and modifying their use of electricity consumption. This

will be a deliberate action to ease the demand and lower the prices.

Fig. 3 Wholesale Competition Market

Over the period from 2003 to 2008, competitive supply will become increasingly available to

smaller sectors of the market. Then in 2009, full retail competition will be introduced as the final

stage of restructuring. Once this takes place, all consumers will have the right to choose their

electricity supplier. The emergence of traders, brokers and consumer unions will appear in the

market.

Fig. 4 Retail Competition Market


In 2009, power generation will be competitive and multiple power sale businesses will be

competing to sell electricity to all customers, even to homes. The KPX will be operating an

efficient spot market to coordinate and price real-time operations. This will be the final step in

the restructuring process.

Taking current restructuring of the electricity industry into consideration, the government is

making a master plan to help the coal power industry on the restructuring condition.

Table 1. Coal consumption in power generation in Korea

Capacity

(MW)

Composition

(%)

Number of

Generator

Coal

Consumptio

n

(1000 ton)

Imports 12,740 26.3 26 33,369

Domestic 1,291 2.7 9 2,848

Production

The long-term contract encourages the consumption of anthracite in power plants. In addition,

the financial assistance in compensation for excessive cost could strengthen the competitiveness

of coal power plant.

Table 2. Outlook for Coal-fired power generation based on the Fifth National Plan for Energy Supply (’99’15)

(unit : 10,000kW)

Coal Capacity Variation

(unit)

Number of

Generator

Closedown

plan

Imports 1,280 70 (1) 23 262(6)

Domestic

Production

40 - 2 69(6)

Although the long-term contract and compensation of over-cost could maintain stabilization of

the coal industry, the effect of the restructuring can be declined. Moreover, there is uncertainty of

durable long-term contract.

However, the effect of the restructuring of the power industry on the coal industry in Korea has

not been identified and more studies and thus analysis on the effect are required.


DEREGULATION OF THE KOREAN

ELECTRICITY MARKET

(Current Status and Prospects for the Future)

Chang-Seob Kim

Korea Energy Management Corporation

(Korea)


Contents

1. Basic Information on Korea

2. Power Market Structure of Korea

3. Generation Capacity and Mix

4. Purpose and Background of Restructuring

5. Power System Restructuring History of Korea

6. Time Schedule of Power System Restructuring

- Current Market Structure

- Generation Competition Phase (Phase II : 1999 - 2002)

- Wholesale Competition Phase (Phase III : 2003 - 2008)

- Retail Sale Competition Phase (Phase IV : 2009 - )

7. Primary policy issues in restructuring of power industry

8. Detail Timetable for the Industry Reform

9. Final Official Plan for Generation Expansion in 1998


Basic Information on Korea

F Korea (South)

- Population 45 Million

- GNP/capita US$ 8,000 in 1999(Economic Risks in 1997)

- Location : Far-East Asia (Surround by China, Russia, and Japan)

- Power System : Isolated Power System


Power Market Structure of Korea

Currently, KEPCO is the Monopoly Enterprise Owing and

Operating Gen-Trans-Dist Facilities

KEPCO possesses 94.2% of Generation market

(unit: MW)

company

KEPCO

Hanwha(IPP)

Etc (Hydro)

Total

capacity

40,660

1,500 1,015

43,175

Composition

ratio(%)

94.2 3.5

2.3

100


(unit: MW)

U.S.A.

France

817,280 China 236,541 Japan 233,740

111,350 G.B. 70,210 Thailand 17,500


KEPCO(Korea Electric Power Corporation)

Key Player in Economy & Industry

94% of Power

Generation

100% of

Transmission

u 94% dependency on imported

energy resources

100% of

Distribution


Generation Capacity and Mix

Generation


Purpose and Background of

Restructuring

Efficiency Improvement in Electric Power Industry

Increase of IPPs

Customer's Rights to Choose a Commodity

External Environments : OECD, APEC, IMF, etc.


Power System Restructuring

History of Korea

◦ In 1996 Management performance Evaluation by an independent entity

– As a precondition of restructuring, a phased-in approach is appropriate

for pursuing KEPCO’s privatization, because of the fast increase of

demand

◦ In June 1997 Establishment of Electricity Industry Restructuring

Committee

– The Committee decided to draw a plan for restructuring of the Industry

◦ In July 1998 Government announcement of directive to privatize state-run

public enterprises

◦ In November 1998 Public hearing by MOCIE on the Restructuring plan

◦ In January 21 1999 Public announcement by MOCIE on the Blue Print of

Restructuring


Time Schedule of Power

System Restructuring

PHASE I PHASE II PHASE III PHASE IV

Current

Monopoly

Competition in

Generation

Wholesale

Competition

Retail

Competition

1998 1999 2003 2009


Current Market Structure

KEPCO

Electricity

Generation

Electricity

transmission

Electricity

Distribution

IPPs

- KEPCO is

monopoly entity owing

electricity generation,

transmission and

distribution

- IPPs should sell their

generated electricity by

wholesale to KEPCO

. Avoided Costs

. Embedded Costs

consumer


Generation Competition Phase

(Phase II : 1999 - 2002)


Power Power Generation Co. Co.

( owned) )

(Government owned)


Bid


Power Power Generation Co. Co.

( )

(private)


Bid

- First, Cost-based G-Pool

Model will be adapted.

(Audited Cost-based

Economic Dispatch like

Chile Model)

Bid

Bid for selecting electric power

generating companies

- Next, Price-Bidding will be

adapted.

Current

Operating

IPPs (private)

PPA

Transmission(KEPCO)

Distribution(KEPCO)

- KEPCO continues to

control electric power

transmission and

distribution

Consumer

- IPPs can sell their

products to Market or

directly to Pool by PPA


Wholesale Competition Phase

(Phase III : 2003 - 2008)

Power Power Generation Co. Co.

(private)

Bid

Current

electric power

generating

companies

(private)

Bid

PPA

purchase

Transmission Company

Distribution Co.

Distribution Co.

Power Power Generation Co. Co.

(private)

Bid for selecting electric power

generating companies

Bid

Direct

dealing

purchase

Distribution Co.

Distribution Co.

- Distribution Sector will

be separated

from KEPCO

- All will be privatized

(if possible)

- Introduction of

Wholesale Competition

- Opening of

transmission network

for Bilateral Contracts

(only to Large

Consumers)

Consumer

Consumer

Large

Consumer


Retail Sale Competition Phase

Power Power Generation Co. Co.

(private)

Bid

(Phase IV : 2009 - )

Power Power Generation Co. Co.

(private)

Bid

- Retail Competition

(Opening of

Distribution

Networks)

Direct

dealing

Bid for selecting electric power

generating companies

- Bilateral Contracts

Transmission Company

purchase

Distribution Co.

Distribution Co.

purchase

Distribution Co.

Distribution Co.

Consumer

Union Consumer Consumer


Primary policy issues in

restructuring of power industry

Long-term power demand-supply plan

Tariff policy

Burden of power sector for public interest

Adjustment of related laws

Other issues


Long-term power demandsupply

plan

Under the current KEPCO’s monopoly system, the government leads

the power demand forecast and determines generation mix.

In case of power industry restructuring:

- Market can Provide Future Capacities

- Energy Mix Problems (Korea Imports energy

resources more than 94%)

- Energy Security

=> We hope that Market will accomplish these issues.


Tariff policy

Is it Possible to get the Public Acceptance to Apply SMP (the same

price)

- Currently, KEPCO applies different tariff by sectors

(incentives to industry and agriculture)


Uses

Residential

Commercial

&public

Educational

Industrial

Agricultural

Street

Lighting

total

Tariff

(won/kW)

(index)

100.95

(139)

102.96

(141)

85.76

(118)

54.49

(75)

42.60

(59)

62.13

(85)

72.79

(100)

Sales

Composition

(%)

18.5 19.8 0.9 57.9 2.1 0.8 100.0


Adjustment of related laws

Formation of different power industry structure by power industry

restructuring

- Seeking to amend primary laws, including “Electricity Business Law” as a first

priority, until 1999 and seeking amendment of related laws and legislation of special

act in parallel


Other issues

Minority shareholders

-To protect minority shareholers’ opposing KEPCO’s privatization,

. Persuasion through assuring expectation and credibility for the government’s future

policy

. Seeking measure to arrange fund in parallel to be needed in case of redemption

Labor request union

- Employment issues for employees

- Term for employment transfer affect asset disposal

- Seeking policy consideration, such as employee stock-sharing plan which allows

allocation of a certain shareholding to employees


Detail Timetable for the Industry

Reform

1999.1

Announcement of Electric Power

Industry Restructuring Plan

• Preparation of Regulatory framework


The First stage

1999.1

~

1999.12

for Introduction of competition into

generation sector

-set up regulatory framework

-asset unbundling for G/T/D

-establish subsidiaries for generations

-prepare auction market for generation


The Second stage

1999.10

~

2002

• Starting Competition in Generation

-privatization of generation sector (if possible)

(1999.10~2002)

-Bring competition between generating entities

• Price Bidding (Final Goal)

• In the initial stage of privatization, Audited-

Costs Based Economic Dispatch

(G-Pool Model)


• Unbundling of Distribution Sector from

KEPCO


The Second stage

1999.10

~

2002

- privatisation of Distribution Co.

(2000~2001)

• Establishment of Independent Regulatory

Agency (1999.10)

-Establish Electricity Committee

under Government

-Perform restructuring and overall regulatory

works


The Second stage

1999.10

~

2002

• Preparation of Two-way Electricity Auction

Market (2000~2002)

-Set up operation rules for Pool

-Educate Operation Staffs

-Set up Facility and Software


• Wholesale Competition


The Third stage

2003

~

2009

-run an electricity trading system

under open competition by genco’s and

disco’s

• Permit Direct Purchase of Electricity

for Large-scale consumers (Bilateral

Contracts)

• Establish and run a Specialized Independent

Regulatory Agency

-establish a separate independent regulatory

agency


The Fourth(final) stage

after

2009

Retail Competition

-remove regional monopoly in distribution sector

-new types of electricity business will emerge such as

Traders, consumer union, suppliers

-Consumers’ Commodity Choice Guaranteed


Final Official Plan for Generation

Expansion in 1998

Electricity

Sales

( 10GWh)

DSM

(10MW)

Peak

Demand

(10MWh)

Annual average

increasing rate

(%)

1998

2000

2005

2010

2015

‘90~’00

‘01~’05

‘06~’10

‘11~’15

‘98~’10

‘98~’15

1,967

2,213

4.8

83

3,524

3,961

2,979

3,530

3,934

3.3

213

441

546


5,338

6,327

7,109

3.4

6.1

3.5



6.1

3.5

2.2

4.4



2.4

4.5

3.8 – 3.9


Final Official Plan for Generation

Expansion in 1998

(Capacity Mixes by Energy Sources)

- Will it be possible to maintain the forecasted Capacity

Mixes in a Competitive Electricity Market

100%

80%

60%

40%

Oil

Hydro

LNG

Coal

20%

Nuclear

0%

1997 2005

2015


Coal consumption in power

generation in Korea

•Taking current restructuring of the electricity industry into

consideration, the government is making a master plan to

help the coal power industry on the restructuring condition

Capacity

(MW)

Composition

(%)

Number of

Generation

Coal Consumption

(1,000 ton)

Import 12,740 26.3

26 33,369

Domestic

Production

1,291 2.7

9 2,848


Outlook for Coal-fired power generation

- based on the National Plan for Electric Supply (’99’15)

•The long-term contract and compensation of over-cost

could maintain stabilization of the coal industry, the effect

of the restructuring can be declined

Capacity

(MW)

Variation

(unit)

Number of

Generation

Closedown

plan

Import 1,280 70( 1)

23 262(6)

Domestic

Production

40 -

2 69(6)

The effect of the restructuring of the power industry on

the coal industry in Korea has not been identified and

more studies and thus analysis on the effect are required


ENERGY DEVELOPMENT

PLANS

Mr Shih-Ming Chuang

Division Manager, Energy Commission

Ministry of Economic Affairs (MOEA)

Chinese Tapei


THE ENERGY DEVELOPMENT PLANS

IN CHINESE TAIPEI

Shih-Ming Chuang

ENERGY COMMISSION

MINISTRY OF ECONOMIC AFFAIRS

1


Contents

I. Energy Situation

II. Future Energy Policy Direction

III. Energy Development Plans

IV. Coal Demand and Supply Outlook

V. Closing Remarks

2


I. Energy Situation

3


1. Structure of Energy Supply

☛Percentage of Imported Energy in

2000 : 97%

☛Average Annual Growth Rate from

1980 to 2000 : 5.8%

6 %

2

6

71

15

34.3

Million KLOE

58.6

Million KLOE

14 %

4

4

55

23

106.3

Million KLOE

9%

2

7

51

31

Nuclear

Hydro

Natural Gas

Petroleum

Coal

1980 1990

2000 year

Dependence

on imports: 86.4% 93.4%

97.1%

4


2. Structure of Energy Consumption - by energy forms

☛Total yearly electricity consumption increases

90.9

Million KLOE

49

% Electricity

52

Million KLOE

34 %

6

29.6

Million KLOE

40 %

3

44

3

37

Natural Gas

Petroleum

52

8

13

11

Coal

1980 1990

2000 year

5


3. Structure of Energy Consumption - by sectors

Energy consumption by the industrial,

residential, and transportation sectors has

increased substantially since 1980.

90.9

Million KLOE

3%

6

2

6

Non-energy Use

Others

Agricultural

Commercial

29.6

Million KLOE

2%

6

3

2

10 %

12

52

Million KLOE

2%

6

3

4

11

6

58

12

16

55

Residential

Transportation

Industrial

65

1980 1990

2000 year

6


4. Installed Capacity of Power Stations

☛1990 - 2000 Average Annual Growth Rate

•Total Installed Capacity: 7.3%

•Peak Load: 5.9%

14%

15

59

11

9,056MW

17,809MW

5 %

29

14

4

27

21

34,773MW

6 %

15

15

13

13

15

23

IPP

Cogeneration

Nuclear

Hydro

Gas-Fired

Oil-Fired

Coal-Fired

1980 1990 2000

Reserve Margin: 8.2 % 7.4 % 12.6 %

7


Power System (2000)

1st Nuclear

Linkou 2nd Nuclear

Hsiehho

Ever Power IPP

Shenao

Kuokuang IPP

Peak Capacity: 29,124 MW

Hsintao IPP

Peak Load: 25,854 MW

Tunghsiao

Reserve: 3,270 MW 12.6%

Hoping IPP

Taichung

Starenergy IPP

Takuan Hydro

Mailiao IPP

Mingtan Pumped Storage

Penghu Chiahui IPP

N

Sunba IPP

Hsinta

Nanpu

Talin

3rd Nuclear

IPP ( 2,250 MW)

Nuclear ( 5,144 MW)

Thermal (17,818MW:

coal 8100; oil 5404; gas 4314 MW)

Hydro ( 4,422 MW)

Extra High Voltage Substation

345 kV Transmission Line

8


5. Status of Petroleum Industries

1.Refineries: 2

➧ Chinese Petroleum Corp. ( Capacity:770KB/D)

➧ Formosa Petrochemical Corp.( Capacity:450KB/D;Operation:

300KB/D)

2. Importers: 4

3. Exporters2

4. Wholesalers for gasoline/diesel29

5. Gas Stations: 2,150

(CPC: 583; Contract with CPC:1,027; Contract with FPCC:450)

6. LPG Stations: 10

7. Fishing Vessel Fueling Stations: 38

9


6. Natural Gas Infrastructure

Projected LNG Terminal

Shin Taur

Shin Chu

Yang Ming Shan

Shin Jr Shin Hu

Shin Lung

Shin Tai

The Great Taipai

Shin Hai Shin Shin

Tung Hsiao

Chu Chien

C.P.C.

Yu Miao

Shin Chung

Shin Chang

Shin Lin

240KM

Shin Yun

Shin Chia

Chu Ming

City Gas Utility

LNG Terminal Facility

Yung An LNG Terminal

Shin Nan

Shin Kao

Nan Jen

Shin Ying

Shin Hsiung

Shin Ping

Underground Gas Storage

Projected LNG Terminal

Trunk Pipeline

Ring Pipeline

Submarine Pipeline

Constructing New Pipeline

Distribution Station

10


II. Future Policy Direction

11


❏The structure of the primary energy supply for

the year 2020 will be as follows

☛ Coal 27-30%

☛ Petroleum 37-40%

☛ Natural Gas 14-16%

☛ Hydro 1-3%

☛ Nuclear 13-15%

☛ Renewable Energy 1-3%.

12


❏The structure of the installed capacity for the year

2020 will be as follows

☛ Coal-fired 35-37%

☛ Oil-fired 4-5%

☛ Gas-fired 27-29%

☛ Hydro 9-11%

☛ Nuclear 19-20%

☛ Renewable Energy 1-3%.

13


III. Energy Development Plans

1. Deregulating Energy Enterprises

2. Promoting Privatization of Electricity Sector

3. Establishing a Nuclear-Free

Chinese Taipei

4. Strengthening Energy Efficiency & Energy Conservation

5. Augmenting Research & Development on Renewable

Energy

14


1. Deregulating Energy Enterprises

❏Liberalization of Petroleum Industry

1. Privatization of CPC

➠Expected date : Jan. 2004.

2. Legislation

➠Petroleum Administration Law (draft) has been

approved by Legislature : Sep. 2001.

➠Promulgation : Oct. 2001.

15


Set up Petroleum Fund

Source Amount Purpose

1.Imported crude

oil and petroleum

products

2.Indigenous

explored oil

3.Petroleum byproducts

of

petrochemical

industry

Petroleum Fund

1.For government Security

Stockpile

2.For subsiding oil distribution

& marketing for the remote

and offshore regions

3.For encouraging oil and

natural gas exploration

4.For energy R&D

5.For other necessary

measures

16


2. Liberalization of Electricity Industry

❏The revised draft of the Electricity Law

☛The revised draft of the Electricity Law will

widely open the operating pattern of power

generation. Whenever the legislature

approves the draft, the monopoly of Taiwan

Power Company will be eliminated.

17


Revised Draft of Electricity Law

❏ To allow Taipower to be vertically integrated and independent of

the privatization process.

❏ To allow new industries including generation, transmission, and

distribution to enter the market whenever the law is approved.

❏ To establish the Independent System Operator(ISO).

❏ To allow electricity customers to choose their suppliers.

❏ Electricity industries must install certain percentage of clean

energy capacity.

❏ Integrated utility and distribution company have the obligation to

guarantee the supply of electricity sufficiently.

❏ To allow generators to supply power directly to nearby users

through private power lines.

18


Basic Structure of Liberalization

Integrated Utility

Wholesale

Generation

•Existed Plants

•Under-construction

•Approved Projects

•Future Projects

Generators

• 1st, 2nd round IPPs

• 3rd round IPPs

(Non-utility)

After PPA

terminated

Generators

•IPP's new units

•New IPPs

(Non-utility)

Selfgenerators

transmission

Distribution

ISO

Bilateral Contract

Direct Supply

Supply Obligation

Captive Customers

(regulated tariff)

Contestable

Customers

(Unregulated tariff)

Direct Self-use

Users Users

(Unregulated tariff)

19


IPP Programs

Policy Objectives

•To meet power demand at reserve margin of 20%

1st & 2nd rounds (1995): 10,260 MW (1997-2002);

3rd round (1999): 2,840 MW (2003-2004)

To balance regional supply and demand

Areas Peak Demand Peak Capacity

North 46% 25%

Central 26% 37%

South 28% 38%

•To prepare for power liberalization

1st & 2nd rounds: base load, medium load

3rd round: gas fired, medium load

20


Status of IPP Projects

Items

IPP

Capacity

Status

Policy

Achievement

Capacity

(MW)

Fuel

Types

Areas

7,220

(20% of

Total

36,680

MW in

2004)

Preparatory

1,950

Gas

4,120

North

3,280

Constructing

3,020

Coal

3,100

Central

490

Operating

2,250

South

3,450

Reserve

Margin will

be 20% in

2004

Gas Share

will be 33%

in 2004

North will be

selfsufficient

in

2006

21


3. Establishing a Nuclear-Free Chinese Taipei

☛Formulating a statute for the early decommission of the

existing three nuclear power plants

4. Strengthening Energy Efficiency & Energy

Conservation

☛Establishing an energy efficiency index and auditing

system

☛Implementing an auditing system for energy users

☛Raising the energy efficiency standards of equipment

and revise fuel economy standards for vehicles

22


5. Augmenting Research & Development on

Renewable Energy:

☛Implementing the Measures for Promoting Solar

Water-Heating Systems (15-20% subsidized)

☛Implementing the Measures for Promoting Solar

Photovoltaic Systems (up to 50% subsidized)

☛Implementing the Measures for Promoting

Wind-Power Generators (up to 50% subsidized)

☛Formulating the law and the program for

developing renewable energy respectively

23


IV. Coal Demand and

Supply Outlook

24


Coal Demand

Unit:million MT

Consumption

Year

Steam Coal

Total

Coking Coal

PowerGen. Cement Co-gen Others Sub.Total

2000 21.9 2.2 7 8.4 39.5 5.1 44.6

2005 24.7 2.2 8.3 9.4 44.6 5.8 50.4

2010 30.4 1.8 8.5 5.8 46.5 5.8 52.3

2020 42.8 0.8 8.4 1.8 53.8 5.7 59.5

2025 50.3 0.4 9.5 2.8 63 5.7 68.7

25


Coal supply

Unit Million M.T.

Year Domestic Imported Coal Total

Steam Coking Subtotal

2000 0.1 39.6 5.1 44.7 44.8

2005 - 44.6 5.8 50.4 50.4

2010 - 46.6 5.7 52.3 52.3

2020 - 53.8 5.7 59.5 59.5

2025 - 63 5.7 68.7 68.7

26


Trend of Power supply

and Coal consumption

Year 2000 2010 2020 2025

Power Installation

Coal-fired (%)

39.90 50.40 50.30 47.10

Power Supply

Coal-fired (%)

42.00 41.70 42.30 45.70

Coal for Power Generation

(Million Ton)

21.9 30.4 42.8 50.3

Note: Power installation and power supply exclude cogeneration.

27


CO 2 Emission-Energy Energy Sector

year 1995 2000 2005 2010 2020 2025

Per Capita CO2 Emission

7.6 9.8 10.7 11.9 15.3 18.1

(ton)

Total CO2 Emission

162 218 247 284 380 456

(million ton)

28


V . Closing Remarks

❏ The energy development plans in Chinese Taipei aims

at sustainable development through the integration of

the 3E (economic development, environmental

protection, and energy security).

❏ Coal may possibly be utilized as a quasi-carbon-free

energy in Chinese Taipei.

❏ Coal is abundant and price-competitive, therefore, the

outlook of coal in Chinese Taipei will still be relatively

prosperous in the future.

29


SESSION 3:

Coal and Global

Environment

Chair: Dr Frank M Mourits

Climate change Technologies Initiative

Office of Energy Research and Development

Natural Resources Canada


IMPACT OF KYOTO

MECHANISM ON COAL

Dr Yoshiki Ogawa

General Manager

The Second Department of Research

The Institute of Energy Economics

Japan


Impact of Kyoto Mechanism on Coal

The Institute of Energy Economics, Japan (IEEJ)

Yoshiki OGAWA

Summary

The Kyoto Protocol, presently under review by all parties concerned with a view to

implementing it to prevent the global warming, calls for developed economies to reduce

emissions of carbon dioxide (CO 2 ) and other greenhouse gases (GHGs) to their individual

targeted levels. Meanwhile, those parties are discussing in detail the method of introducing

the Kyoto Mechanism (emissions trading (ET), joint implementation (JI) and clean

development mechanism (CDM)), which provides for flexible measures aimed at carrying out

the protocol in an efficient way. The Kyoto Mechanism is expected to play an important role

in offering a more economically efficient option through emissions trading on the international

market for a economy where costs of reducing greenhouse gas emissions are high, thereby

reducing to an absolute minimum total warming gas cutting costs for the entire world.

Coal is a fossil fuel rich in carbon and there is a good possibility that its utilization will be

limited from the standpoint of solving the global warming problem. In the Asian region,

which is expected to show further economic growth in the future, however, coal is believed to

be an indispensable energy source. Moreover, for a economy like Japan that is endowed with

meager energy resources, it is an essential matter to have the best mix of electric power sources

and the use of coal should not be abandoned solely for the purpose of addressing an

environmental problem. This leads us to study the possibility of introducing a method of

reducing an environmental load, while utilizing coal.

The Kyoto Mechanism suggests the possibility of simultaneously solving the conflicting

problem – supply of energy source and environmental protection. By means of the clean

development mechanism, a more efficient coal utilization technology can be transferred to a

developing economy or economies, while a developed economy or economies can effectively

reduce greenhouse gas emissions through efficient utilization of coal and other projects of

reducing warming gas emissions in that developing economy or those economies. The credit

earned from this scheme can then be used for utilizing coal on the domestic market, thus

realizing an action of solving the problem on an overall basis. In this connection, it will be

necessary to undertake concrete studies in the future to find out what programs or systems are

needed under which utilization of coal and implementation of the Kyoto Mechanism can be

achieved simultaneously.


1. Promotion of Coal Utilization and Inherent Problems

(1) Trend in World’s Coal Consumption and Its Prospects

World’s coal consumption continued to increase at an annual rate of about 2% throughout

the 1970s and 1980s hand-in-hand with an increase in the total energy consumption. In

particular, coal played an important role in the 1980s as an alternative fuel to oil along with

natural gas and nuclear energy. Entering the 1990s, however, an increase in the consumption

began to slow down due to negative factors such as a slump in oil prices, a shift to natural gas

in Europe and the U.S., and the sluggish Asian economy (see Figure 1).

The proportion of coal energy to the total energy consumption, on the other hand, remains

at nearly 30%, though it is decreasing gradually. Underlying this trend are: a sift to natural

gas that is accelerating worldwide; a continuous increase in coal consumption in

coal-producing economies (the U.S., Australia, etc.) in and after the 1990s; and an increasing

coal consumption in the Asian region. 4

4 The coal consumption in China decreased dramatically in 1997, 1998, and 1999 because of the closure

of small-scale coalmines and measures addressing environmental issues.


Figure 1. Increase of Consumption and Percentage Distribution of Each Energy Source

(World Total)

800

600

Mtoe

1971-1980

1981-1990

1991-1998

400

200

0

(Source) OECD/IEA

Coal Oil Gas Others

1998

1990

1980

1971

25.7%

28.0%

27.5%

29.6%

Coal

Oil

Gas

Others

0% 20% 40% 60% 80% 100%

(Source) OECD/IEA

Table 1. Long-Term Prospects for Growth in Economy and Energy Demand (1997-2020)

Economy Average Growth (%) Energy Demand Average Growth (%)

US.DOE/EIA S&P IEA US.DOE/EIA S&P IEA

Base H.Dem L.Dem Base H.Dem L.dem

Developed 2.5 3.4 1.8 2.3 1.7-2.1 1.2 1.5 0.8 1.2 0.9

FUSSR/EE 3.1 6.7 1.8 3.5 3.1 1.4 2.5 0.9 1.3 1.6

Developing 5.0 6.3 2.9 4.8 -- 3.4 4.3 2.2 3.5 3.4

Asia 5.7 7.0 3.3 5.3 -- 3.4 4.3 2.1 3.6 3.7

China 7.0 8.5 4.6 6.7 5.2 3.7 4.6 1.8 3.3 3.4

Others 4.9 6.1 2.6 4.6 4.2-4.9 3.2 4.1 2.3 3.8 4.0

M. East 4.3 5.7 2.2 4.1 3.2 3.1 4.1 2.2 3.3 2.8

Africa 3.9 5.3 2.3 3.6 2.9 2.6 3.5 1.6 2.6 2.8

Latin 4.2 5.5 2.5 4.3 3.2 3.8 4.9 2.2 4.2 3.1

World Total 3.2 4.3 2.0 2.9 3.1 2.1 2.8 1.3 2.3 2.0

(Note) US.DOE/EIA: US.DOE, Energy Information Administration, SP: Standard & Poor’s Platt’s

World Energy Service, IEA: International Energy Agency

(Source) US.DOE/EIA, “International Energy Outlook 2001,”

Table 1 shows the latest long-term prospects prepared by major institutions for the growth

in economy and energy demand both in the world and in each region. Although there were

short-lived concerns about a slump in economic growth and energy demand because of the


worsening Asian economic crisis, energy demand began to increase in the latter half of 1999,

as the Asian economy headed toward recovery. The major institutions estimate that the world

economy will be growing at an average of about 3% annually until 2020. In response to this,

energy demand is expected to increase at an average of about 2% a year.

By region, economic growth rates over the long term are estimated at: 2% or more for the

industrialized region; 3% or more for the former Soviet Union and East-Europe regions; 5% or

more for the Asian developing region; and 3-4% for the other developing region. Likewise,

growth rates of energy demand are estimated at: about 1% for the industrialized region; about

1.5% for the former Soviet Union and East-Europe regions; about 3.5% for the Asian

developing region; and about 3% for the other developing region.

The Asian economic crisis ended up with a temporary phenomenon, and a widely held

view is that the Asian developing region continues to grow steadily as the world’s growing

center until 2020. Naturally, the regional energy demand is expected to surge in response to the

regional economic growth.

Figure 2 shows the trend in energy demand (by energy source) in the world and in the

steadily growing Asian region including Japan; this figure is based on the estimates prepared

by the US Department of Energy (US.DOE) and the International Energy Agency (IEA). In

the 1990s, the energy demand in the former Soviet Union and East-Europe regions declined

drastically due to an economic disturbance, and hence the world’s energy demand showed a

relatively mild upswing (about 1% annually), increasing from 174 million bbl/day (8.7 billion

ton/year) in 1990 to 192 million bbl/day (9.6 billion ton/year) in 1999 on an oil basis.

Figure 2. Prospects for World and Asian Energy Demand and Position of Coal

(1 mil.Boe/D)

(1 mil. Boe/D)

350

300

250

World Total

Hydro &

247

Nuclear

306

250

301

140

120

100

Asia

Hydro &

115

104

200

174

192

Gas

80

Nuclear

77

77

Gas

150

100

Oil

60

40

35

47

Oil

50

Coal

20

Coal

0

26% 22% 21% 19% 24% 23%

0

44% 37% 37% 35% 39% 37%

1990 1999 2010 2020 2010 2020

1990 1999 2010 2020 2010 2020

Actual US.DOE IEA

Actual US.DOE IEA

SourceUS.DOE/EIA, “International Energy Outlook 2001,” IEA, “World Energy Outlook 2000”


On the other hand, as US-DOE and IEA estimate, the world’s energy demand is expected

to grow by a little over 2% annually, reaching 250 million bbl/day (12.5 billion ton/year) in

2010 and 300 million bbl/day (15 billion ton/year) in 2020. Energy demand is thus likely to

increase more steadily over the long term than it did in the 1990s.

With this situation as a backdrop, energy demand in the Asian region (including Japan)

increased from 35 million bbl/day (1.75 billion ton/year) in 1990 to 47 million bbl/day (2.35

billion ton/year) in 1999, showing an annual growth rate of 3.3%. Considering that the Asian

economy experienced a slump in the last two years in the 1990s (and that the Japanese

economy has been sluggish over the last decade), the expansion in energy demand in the Asian

developing region before the economic crisis had been dramatic compared with the world’s

average.

Aside from Japan, which will have to enter a mild growth period, the Asian developing

region is expected to continue growing; the region rode out the economic crisis, and is back on

track toward recovery. The regional energy demand is thus likely to reach 77 million bbl/day

(3.05 billion ton/year) in 2010 and 104-115 million bbl/day (5.2-5.8 billion ton/year) in 2020,

maintaining an annual growth rate of 3.5-4.5%. Because of this rapid increase in energy

demand, various problems may arise in the future on the supply front such as energy security.

“World Energy Outlook 2000” of IEA estimates that the world coal consumption will

increase at an annual rate of 1.7% during the period between 1997 and 2020. Although this

growth rate falls short of those expected in the total energy consumption (2%) and natural gas

(2.7%), the world coal consumption is likely to maintain the average growth rate for the last 30

years, according to the estimate. The coal consumption in the OECD economies may slow

down due to a shift in power-generating and heating fuels from coal to natural gas, but

increasing consumption in developing economies will probably offset the downturn. In

particular, China and India, both of which are blessed with domestic coal resources, are

expected to consume an increasing amount of coal to generate power in response to their

economic growth. In fact, these two economies are most likely to bring about as much as

two-thirds the increase in coal consumption expected during the period mentioned earlier.

(2) Japan’s Energy Prospects and Position of Coal

Although an array of economic measures have been adopted and implemented since the

Japanese bubble economy burst at the beginning of the 1990s, there have been no signs of solid

recovery over the last 10 years: an economic growth rate remained at 1%, more or less, during

this period. Energy demand increased at about 1%, accordingly.

The long-term prospects for energy supply and demand, which were revised in 1998, were

based on an estimate that the economy would continue to grow at an annual rate of about 2.5%.

The latest prospects as of 2001, however, estimate that the economy will further slow down,

being saturated over the long term. Energy demand between now and 2010 or 2020 is also

expected to slow down considerably.

Another factor that may depress energy demand is the need to further promote energy

saving in order to achieve the 2010 reduction target for greenhouse gases, which was mandated

by the Kyoto Protocol.

Japan’s energy demand stood at 593 million kl as of 1999 in terms of crude-oil equivalent.

The standard case presented by the latest long-term prospects for energy supply and demand,


which are being revised, estimates the energy demand in 2010 at 622 million kl. This amount

falls far short of the level previously estimated by the 1998 standard case; it rather corresponds

with the 1998 countermeasure case.

This situation can be attributed to the success of a series of energy-saving efforts that is

already incorporated into the existing policy: there was a need to further promote energy

saving in 1998, a quest in which companies have been voluntarily playing a major role.

Table 2. Japan’s Long-Term Prospects for Energy Supply and Demand

(Revised Version) and Position of Coal

(AV: Actual Value, 1 mil. Kl-oe, Share: %, CO2: 1 mil. t-C)

Year Outlook (1998) Outlook (2001)

FY1990 FY1999 FY2010 FY2010 FY2020(Reference)

Item Base Measure Base Measure Base Measure

Prim.

Energy

526 593 693 616 622 602 658 611

CO2

To Y90

287 313

(8.9%)

347

(20.9%)

287

(0.0%)

307

(6.9%)

287

(0.0%)

321

(11.7%)

273

(-4.9%)

AV (%) AV (%) AV (%) AV (%) AV (%) AV (%) AV (%) AV (%)

Oil 307 58 308 52 358 52 291 47 280 45 271 45 282 43 266 44

Coal 87 17 103 17 108 15 92 15 136 22 114 19 163 25 105 17

Gas 53 10 75 13 85 12 80 13 82 13 83 14 70 11 86 14

Nuclear 49 10 77 13 107 15 107 17 93 15 93 16 112 17 108 18

Hydro 22 4 21 4 23 4 23 4 20 3 20 3 20 3 19 3

Geotha 1 0 1 0 3 1 4 1 1 0 1 0 1 0 1 0

New E 7 1 7 1 9 1 19 3 10 2 20 3 10 1 26 4

(Source) Prepared from reports published by METI

The 1998 long-term prospects estimated that nuclear energy would be widely introduced

by 2010. The latest prospects, however, are expected to revise the proportion of nuclear

energy downward according to the realistic figures based on the long-term electric power plan.

Carbon-dioxide emissions, as a result, are likely to increase by 7% compared with the 1990

levels. Since it is a condition of the ground design (which aims to reduce greenhouse gasses,

or to comply with the Kyoto Protocol) to maintain CO 2 emissions of energy origin at the 1990

levels, there is a need to further strengthen measures that are necessary to attain this target.

A further shift to natural gas can be one of the effective options for the latest prospects. As

shown in Table 2, however, demand for natural gas itself is not expected to increase

dramatically; rather, it is likely to end up expanding its proportion to the total energy mix. This

is because natural gas will be introduced, with energy-saving measures being strengthened and

total energy demand being controlled. While the Japanese economy is becoming increasingly

saturated, coupled with the promotion of energy-saving measures, Japan’s energy demand will

probably slow down. There seems to be no basis that demand for natural gas will surge

unless it is far more cost-effective than any other energy sources.

The recent sluggish economy may lead to a slowdown in electricity demand. But there is

a need to make up for part of the downturn of nuclear power generation with other energy

sources. The recent electricity-supply plan places more emphasis on LNG and coal as energy

sources for power generation, and it is a priority issue for Japan’s energy policy to have the


est energy mix for power generation. It is thus becoming necessary to depend partly on coal

consumption for the time being.

Coal fired power plants recently constructed in Japan are equipped with closed belt

conveyors that convey coal from ports all the way to coal silos. Coal crushed up into fine

powder in a mill is blown directly into a boiler. Filtered, desulfurized, and denitrified

emissions are released into the air without any pollutants. Moreover, most of by-products

such as ash and gypsum are utilized as materials for cement, plaster boards, and the like. As

the operations of this closed system expose no coal, it can be set up even in the vicinity of

national parks without causing any controversy. Although the construction of the system

itself costs a lot, it has sufficient cost competitiveness compared with other power generation

systems.

(3) Coal Consumption and Global Warming Issue

As mentioned above, coal continues to be an essential energy source because of its

increasing consumption in developing economies, and the position it occupies in Japan’s

energy supply. But this is not necessarily a welcome trend in view of finding solutions to the

global warming issue.

Generally speaking, large part of CO 2 , a greenhouse gas that is said to be the largest

contributor to global warming, is produced by burning fossil fuels; coals produce more CO 2

than any other burning fossil fuels. From the viewpoint of measures against global warming,

therefore, it is desirable to pursue more efficient energy consumption, and to shift from coal to

other fossil fuels 5 , nuclear energy, and natural energy that produce less CO 2 .

Each economy, however, does not necessarily pay attention to environmental issues when

selecting energy sources. China and India, for instance, are consuming an increasing amount

of coal to maintain their economic growth just because coal is the cheapest energy source

available in those economies. On the other hand, diversifying energy sources is one of the

essential policies of those economies (including Japan) dependent heavily on imported energy

sources – a quest in which coal plays an important role. As a shift to alternative energy

sources involves a major conversion of facilities, a long-term plan is indispensable. Under

these circumstances, there is a need to find solutions to these difficult problems, taking into

account both economic efficiency and environmental improvements.

As major coal fired plants have materialized the complete closed system, it may not be

reasonable to eliminate a coal alternative just because of its only one drawback – i.e., a

relatively large amount of CO 2 emissions. Considering energy supply and demand in the

Asian region over the long term, therefore, it is important to leave coal as an alternative energy

source. In fact, the Kyoto Mechanism has a great potential for resolving this problem.

2. The Kyoto Protocol and the Kyoto Mechanism

(1) UNFCCC and the Kyoto Protocol

5 The ratio between major fossil fuels in terms of their approximate basic units of CO2 emissions is: 1

(coal): 0.8 (oil): 0.6 (natural gas). In generating the same amount heat, CO2 emissions can be reduced by

about 40% if natural gas is used instead of coal.


UNFCCC 6 is a convention that aims to address and prevent global warming on a global

scale. The convention was adopted by the 1992 UNCED (United Nations Conference on

Environment and Development), which was held in Brazil, and came into force in 1994. It is

based on a general awareness that an increase in greenhouse gases (primarily CO 2 produced by

fossil fuels) associated with the economic activities of mankind will result in global warming

(a rise in temperature), thereby creating serious impacts on the environment – e.g., the

disappearance of land, climate changes, and natural disasters. As greenhouse-gas emissions

are expected to surge in developing economies whose economies are growing, there is a

common understanding behind the convention that the greenhouse-gas issue should be

addressed on a global scale.

The Kyoto Protocol was formulated by COP3 (Third Conference of the Parties to the U.N.

Framework Convention on Climate Change), which was held in Kyoto in 1997. The Protocol

imposed “the establishment of numerical reduction targets” on industrialized economies in

order to further materialize global-warming preventive measures set forth by the UNFCCC.

Moreover, it calls for those economies listed on its Annex B (the Annex B economies) to set

reduction targets for greenhouse gases based on the 1990 levels of their emissions, and to attain

those targets in terms of the average annual amount of emissions during the period between

2008 and 2012. The Annex B economies 7 are required to reduce greenhouse-gas 8 emissions

by 5.2% compared with the 1990 levels.

(2) Reduction Target of Each Economy and its Reduction Costs

What matters here is a reduction target imposed on each economy. Numerical targets for

major economies are: 6% for Japan,; 7% for the U.S,; 8% for EU; and ±0% for Russia. These

targets, however, were not necessarily calculated based on economic and scientific methods;

rather, they are very much political in nature. The costs of attaining reduction targets, as a

result, vary substantially from economy to economy.

Figure 3 shows an estimation of the CO 2 reduction costs (marginal costs) and the total

costs per GDP of each major economy to attain its 2010 reduction target by means of domestic

measures. As Japan has been pushing ahead with energy-saving measures to the maximum,

its reduction costs are higher than those of any other industrialized economies. Thus, there

are concerns that additional measures against CO 2 emissions may reduce the international

competitiveness of the domestic industry. By contrast, the U.S. and the Oceanian economies

still have low-cost measures. The amount of their CO 2 emissions, however, is expected to far

exceed their Kyoto targets because of expanding energy demand. The total costs per GDP, as

a result, will increase. 9 If each industrialized economy is to implement global-warming

measures by itself, negative impacts on its domestic economy will not be negligible.

6 United Nations Framework Convention on Climate Change

7 A total of 38 economies listed on the Annex B of the Kyoto Protocol: industrialized

economies including Japan, the former Soviet Union states, and the former

East-European economies (EU has a single target as one region) = “Bubble”

regulations (see footnote 10)

8 Greenhouse gases refer to CO 2 , CH 4 , N 2 O, HFC, PFC, and SF 6 .

9 According to this estimate prepared by EC, the total costs of measures against

CO 2 emissions in 2010 will be: $ 3.2 billion (the U.S.); $ 1.4 billion (EU);

and $ 0.6 billion (Japan).


Figure 3. CO 2 Reduction Costs and Impacts on Economy of Major Economies (2010)

Marginal Cost

(1990 US$/t-C)

250

200

150

100

50

0

0.36

148.7

0.28

174.2

Marginal Cost

Total Cost

0.17

165.4

0.18

203.1

Total Cost per GDP(%)

0.30

120.8

USA Canada EU Japan AU, NZ

•¦AU: Australia, NZ: New Zealand

(Source) European Commission, "Economic Foundations for Energy Policy"

December 1999

0.4

0.3

0.2

0.1

0

(3) The Kyoto Mechanism

The purpose of the Kyoto Mechanism is to reduce the costs of attaining CO 2 reduction

targets on a global scale; it is a market-based flexible mechanism 10 designed to reduce CO 2

emissions in the most cost-effective and efficient manner. Based on the performers and the

patterns of its trade, this mechanism can be broadly categorized into emissions trading (ET),

joint implementation (JI), and clean development mechanism (CDM).

For those economies including Japan, energy-saving measures of which have progressed

to a considerable extent, the marginal costs of reducing greenhouse-gas emissions are

extremely high. By contrast, developing economies whose economic levels remain relatively

low or which are yet to improve the efficiency of energy consumption still has a number of

less-expensive measures for reducing greenhouse-gas emissions. Through a “market,” the

Kyoto Mechanism facilitates trades among these economies (or business proprietors) that have

different reduction costs, thereby providing them with economic merits.

Figure 4 shows the basic concept of the Kyoto Mechanism. Suppose there are Performer

A and Performer B, both of which have their own reduction targets for a specific year;

10 A flexible mechanism can be categorized into banking (if a certain economy

has achieved its reduction target for a specific target period with a good margin,

that economy can reserve the balance for the next target period), bubble (Two

or more economies are entitled to jointly attain their numerical targets. EU

will share burdens among its member economies, and redistribute emission quotas

based on the situations of each economy. As a whole, EU is supposed to reduce

greenhouse-gas emissions by 8%), and the Kyoto Mechanism. Generally, a flexible

mechanism refers to the Kyoto Mechanism.


Performer A is likely to attain its target with a good margin (an excess of emission credit),

while Performer B may end up producing more CO 2 than its targeted amount (a shortage of

emission credit). The Kyoto Mechanism enables the both parties to attain their original

targets by having them trade the excess and the shortage of their emission credit with each

other. Performer A can earn profits through the trading. Moreover, it can promote reduction

measures if trading prices are higher than the costs of reducing CO 2 emissions domestically

(because its emission credit can be sold in the market). Performer B, on the other hand, can

reduce the total costs of attaining its target by purchasing emission credit at prices lower than

the costs of reducing CO 2 emissions domestically.

Figure 4. Basic Concept of the Kyoto Mechanism

Performer A

Provider of Emission Credit

The actual amount

of emissions below

the emission quota

Excess

Developing

countries with no

emission quota

Management Control

Certifying Body

The Kyoto Mechanism

Emission

Credit

Performer B

Buyer of Emission Credit

The actual amount

of emissions above

the emission quota

•{

The amount of

emissions to be

reduced

Attainment of

Emission Target

As mentioned above, “lower-cost” reduction measures can be materialized by creating a

mechanism through which emission credit is traded in the “market,” and by establishing a

system where each performer is allowed to attain its target by selling or buying emission credit.

(4) Framework of the Kyoto Mechanism

The following is an outline of the Kyoto Mechanism (see the figure attached).

a) Emissions Trading

The purpose of emissions trading is to trade the emission credit of greenhouse gases

among the Annex B economies, each of which has its own emission target imposed by the

Kyoto Protocol. Within the framework of this system, economies or business proprietors

whose amount of greenhouse-gas emissions has exceeded their targets during the commitment

period between 2008 and 2012 can buy emission credit from other economies that have

attained their targets with a good margin. Buyers of emission credit can reduce the costs of

attaining their targets if the purchasing prices of emission credit are lower than the costs of

reducing greenhouse-gas emission in their own economies.

b) Joint Implementation

Joint implementation is a system where industrialized economies with specific reduction


targets are entitled to incorporate the amount of emissions that they have reduced in other

economies (through their projects) into their accomplishments. By implementing projects for

reducing greenhouse-gas emissions (e.g., energy-saving measures, fuel-conversion systems) in

other economies whose reduction costs are relatively low, the economies, that is, the principals

of the projects, can obtain part of or the entire amount of greenhouse-gas emissions reduced by

those projects.

c) Clean Development Mechanism (CDM)

While joint implementation is intended for trades among industrialized economies that

have specific reduction targets, CDM is a mechanism through which industrialized economies

can obtain the amount of emissions reduced by their projects in developing economies.

Although developing economies have no emission credit, investors (industrialized economies)

are entitled to obtain the amount of emissions that they have reduced below a certain baseline

(the amount of reductions) 11 through investments or other measures. The management of this

mechanism, however, calls for a framework that evaluates and certifies the accomplishments

(greenhouse-gas reductions) of pertinent projects.

3. Utilization of Coal and the Kyoto Mechanism

In addressing the global warming issue, specific obligations to reduce greenhouse gases

are imposed on industrialized economies as immediate measures. When considering the very

nature of this issue, however, it is essential that not only industrialized economies but also

developing economies be engaged in the development and implementation of preventive

measures. The Kyoto Mechanism, as mentioned earlier, is being developed, taking into

account this aspect of the issue. Then, how can the Kyoto Mechanism be utilized for

exploiting coal – a subject that poses a problem to measures against global warming.

(1) Technology of Industrialized Economies

As developing economies continue to consume coal, the amount of CO 2 emissions among

these economies are expected to increase in the future – a situation that will lead to an increase

in CO 2 emissions on a global scale. A drastic shift to other fuels, however, is not feasible

when considering the economic environment of each developing economy. It is thus

necessary to continuously make efforts to shift to alternative fuels, and to improve the

efficiency in coal utilization, thereby reducing CO 2 emissions associated with expanding coal

consumption.

CDM is intended for encouraging developing economies to introduce efficient

coal-utilization technology from industrialized economies. By so doing, developing

economies can utilize coal – an important energy source geographically, and in terms of an

energy-supply mechanism – in a cost-effective and efficient manner, while promoting the

introduction of advanced technology from industrialized economies. Industrialized economies,

on the other hand, can incorporate emission credit obtained through a technology transfer into

11 For instance, there are methods such as “benchmarking” (The balance between

the amount of CO 2 emissions per average electricity generated in a certain economy

and the amount of CO 2 emissions of a newly constructed power station is treated

as “the amount of reductions.”) and “specific project appraisal.” (The balance

between the amount of CO 2 emissions of conventional facilities and the amount

of CO 2 emissions of specific facilities to which energy-saving measure were

introduced is treated as “the amount of reductions.”)


their accomplishments. This will enable them to carry out reduction efforts, the costs of

which are lower than those of their domestic measures; by extension it may contribute to their

own coal consumption that is indispensable for their domestic energy policies.

(2) Combination with Other Measures

Industrialized economies can also maintain domestic coal utilization by implementing

low-cost projects for reducing CO 2 emissions abroad; the projects are not necessarily limited to

those based on coal-related technology. There are many low-cost reduction projects in

industrialized economies, not to mention developing economies – e.g., the streamlining or

reconstruction of manufacturing plants and power stations that are not energy-efficient, and the

afforestation in forest areas with favorable backgrounds.

If the costs of obtaining CO 2 -emission credit through overseas JI or CDM projects are

lower than the costs of reducing CO 2 emissions domestically (by improving the efficiency in

coal utilization, or by shifting to other alternative fuels), it will become possible to attain

reduction targets in a cost-effective manner, while maintaining domestic coal consumption. As

a matter of fact, some U.S. companies are undertaking this “carbon offset” concept, which

aims to promote domestic coal utilization by implementing low-cost CO 2 -reduction projects in

other economies.12

(3) Options for Coal Suppliers

If economies (business proprietors) are to explore JI or CDM projects abroad, while

maintaining domestic coal consumption, various efforts (e.g., the exploration, evaluation, and

continuous management of projects) will be required of them. Thus, it will be of much benefit

to coal users if emission credit can be obtained at the time of purchasing coal. 12

For instance, economies or companies supplying coal may as well consider a package deal

(emission credit and coal) for users if they can obtain emission credit through low-cost

domestic measures or JI/CDM projects. This will not only reduce the investment load of

users but also widen the options for reducing CO 2 emissions. Coal suppliers, moreover, can

add value to coal, which will improve coal’s competitiveness in the energy market.

4. Future Challenges and Direction

As discussed above in view of the present situation and the future of coal utilization, the

Kyoto Mechanism has great potential for reducing greenhouse gases. The discussions about

the details of the Kyoto Protocol, however, have not been completed, and the framework of the

Kyoto Mechanism is yet to be determined. Under these circumstances, the following issues

must be examined concretely in order to make full use of this system.

(1) Domestic Policy that Gives Incentive to Business Proprietors

It is necessary to motivate business proprietors if they are to promote investment abroad in

order to make full use of the Kyoto Mechanism. This is an issue that should be addressed

individually by each economy that has a reduction target. Specifically, domestic measures

such as direct regulations, tax systems, and domestic emissions trading systems should be

strengthened, and voluntary measures should be promoted. In designing domestic emissions

12 AES, a U.S. independent power-generation company, is promoting afforestation

projects in South America, while constructing coal fired power plants in the

U.S.; the purpose is to offset CO 2 emissions of its plants by afforestation efforts.


trading systems, the coordination between governments and business proprietors are

indispensable: they need to cooperate with each other in maintaining their international

competitiveness, attaining their targets, and ensuring international compatibility in the systems

– all of which hold the key to the success of the entire scheme.

(2) Feasibility Studies of Projects at Earlier Stages

Considering that every economy will have to address the Kyoto Mechanism, more or less,

in the future, investors who intend to maintain their international competitiveness need to

obtain projects that can be implemented at lower costs and risks. For this reason, investors

should accumulate resources in preparation for the future by conducting the feasibility studies

and the screening of projects at various locations prior to the establishment of an international

system.

(3) Strengthening Relationships with Host Economies

Of the components of the Kyoto Mechanism, JI and CDM are most likely to be led by

private companies. As is the case with other investments, however, JI or CDM projects to be

implemented in some economies involve various risks – a situation that may hamper

investments in earlier stages. Moreover, there may be a number of cases where issues such as

the calculation of the amount of CO 2 emissions reduced by CDM projects are referred to the

negotiations among concerned parties. It is thus necessary to study those negative risks well

in advance to facilitate a series of transactions (feasibility studies, implementation, and credit

acquisition); a favorable environment must be created in collaboration with host economies. 13

5. Conclusion

As far as the global warming and environmental issues are concerned, coal has serious

disadvantages compared with other energy sources. In addition to environmental issues,

however, each economy is subject to various constraints (geographic and economic constraints,

energy security, etc.) when selecting energy sources. The Kyoto Mechanism has the potential

for simultaneously solving these numerous constraints. It seems to be worthwhile designing

ideas in relation to coal utilization that is required.

Naturally, the benefits of the Kyoto Mechanism are not exclusively for coal utilization; it

could offer a variety of appropriate options to economies and companies, paying attention to

both their individual problems and the global warming issue. The costs of addressing

environmental issues are relatively high in economies such as Japan because of the

disadvantageous circumstances surrounding them. Thus, these economies should consider

the introduction of the Kyoto Mechanism, fully looking into its effectiveness.

13 For instance, Sweden is conducting a number of AIJ (the pilot activities for

joint implementation) for specific economies. These activities, which seem to

be intended for the creation of an energy market in the future, are expected

to strengthen the relationships with host economies in many ways. In the case

of the Netherlands, the government takes charge of investment and the negotiations

with host economies, while private companies push ahead with

joint-implementation-like activities. As is the case with the U.S., implementing

AIJ in various areas with the support of governments leads to the exploration

of prospective projects, and could contribute to creating the partnerships with

a number of host economies.


Framework of Each Kyoto Mechanism

Emissions Trading

•œ A mechanism through which industrialized countries can trade greenhouse-gas emissions

with one another

•œ The Conference of the Parties determines the trading rules

•œ Emissions trading supplements domestic measures for fulfilling commitments

Industrialized

Country A

Industrialized

Country B

Emission

Quota

Excess

Actual Amount

of Emission

Trade

Emission

Quota

Shortage

Actual Amount

of Emission

Joint Implementation

•œ A mechanism through which industrialized countries can trade the amount of emissions

reduced by their projects for greenhouse-gas reductions

•œ Pertinent projects should be authorized by the countries concerned

•œ Pertinent projects should bring about additional reductions in greenhouse gases

Industrialized

Country A

Governments or

Companies

Funds, Technology, etc.

The Amount of

Emissions Reduced

Agreement

Distribution

Industrialized

Country B

Governments or

Companies

Funds, Technology, etc.

The Amount of

Emissions Reduced

”r•o•íŒ¸—Ê

Projects

Reductions in

Emissions

Clean Development

Mechanism (CDM)

•œ A mechanism through which the amount of emissions reduced by the projects for greenhouse-gas reductions

can be traded between industrialized countries and developing countries

•œ Industrialized countries are entitled to incorporate the certified amount of reduced emissions into their accomplishments

•œ Projects benefit developing countries (e.g., technology transfer, environmental improvements)

Industrialized

Country A

Governments or

Companies

Agreement

Developing

Country A

Governments or

Companies

Funds, Technology, etc.

Funds, Technology, etc.

Projects

The Amount of

Emissions Reduced

Management Body

Certification

Reductions in

Emissions


IEE

JAPAN

Impact of Kyoto-Mechanism

on Coal

8 th APEC Coal Flow Seminar

March 4, 2002

Yoshiki Ogawa

The Institute of Energy Economics,

Japan (IEEJ)

APEC Coal


IEE

JAPAN

800

600

World Coal Consumption

Mtoe

1971-1980

1981-1990

1991-1998

400

200

0

Coal Oil Gas Others

(Source) OECD/IEA

1998 25.7%

1990 28.0%

1980 27.5%

1971 29.6%

0% 20% 40% 60% 80% 100%

(Source) OECD/IEA

Note: Others excluding non-commercial energy

Coal

Oil

Gas

Others

APEC Coal


IEE

JAPAN

Specific Characteristics of

World Coal Consumption

• Stable growth rate (1.6%/year, 1971-1998)

1998)

• 23% share in TPES (1998)

• Share of coal in TPES declines but a little

u 1971=26% 1998=23%

• Power sector push coal demand

u 3.3%/year, 1971-1998

1998

• High growth in Developing Countries (DCs(

DCs)

u 4.8%/year, 1971-1998

1998

TPES; Total Primary Energy Supply

Including non-commercial energy

APEC Coal


IEE

JAPAN

World Economy & Energy Outlook

Economy AGR(%)

Energy AGR(%)

DOE

IEA

DOE

IEA

Developed

2.5

1.7-2.1

1.2

0.9

FUSSR/East Europe

3.1

3.1

3.4

3.5

Developing

5.0

--

3.4

3.4

Asia

5.7

--

3.4

3.7

China

7.0

5.2

3.7

3.4

Others

4.9

4.2-4.9

4.9

3.2

4.0

Middle East

4.3

3.2

3.1

2.8

Africa

3.9

2.9

2.6

2.8

Latin

4.2

3.2

3.8

3.1

World Total

3.2

3.1

2.1

2.0

DOE: US Energy Information Administration

APEC Coal


IEE

JAPAN

World & Asian Energy Demand

and Coal Position

(1 mil.Boe/D)

(1 mil. Boe/D)

350

300

250

World Total

Hydro &

247

Nuclear

306

250

301

140

120

100

Asia

Hydro &

115

104

200

174

192

Gas

80

Nuclear

77

77

Gas

150

100

Oil

60

40

35

47

Oil

50

Coal

20

Coal

0

26% 22% 21% 19% 24% 23%

0

44% 37% 37% 35% 39% 37%

1990 1999 2010 2020 2010 2020

1990 1999 2010 2020 2010 2020

Actual US.DOE IEA

Actual US.DOE IEA

Note: Including non-commercial energy

APEC Coal


IEE

JAPAN

World Coal Outlook

• Except stable demand but lower than TPES a

little (1.6%/year 1999-2020, TPES; 2.2%)

• Coal’s s share declines continuously due to

competitively priced Gas (22% 19%)

• 85% of the increase by power sector

• Demand in Asia will grow by 4.2%/year, in

particular in China and India

Asian Coal share in the world will be more 60%

US.DOE/EIA, International Energy Outlook 2001

APEC Coal


IEE

JAPAN

Coal’s Position in the Energy

Policy in OECD

• Possibility of energy shift from coal to gas

depend on gas price, but…..

• Coal contributes Energy Security Policy that it

makes decrease oil dependence

u OECD coal demand will increase to 2020

• Coal demand will increase in power sector

compare a former governments’ plan in Japan

because of delay of nuclear power facility

construction

APEC Coal


IEE

JAPAN

Coal’s Position in the Energy

Policy in DCs

• High economic growth makes increase

coal demand in industry and power

sector

• High coal dependence in power sector

(41%) in particular China (74%), India

(73%)

• Potential of coal production due to coal

reservation and low price energy supply

APEC Coal


IEE

JAPAN

Recent Newest Coal Power Plant

Berth

Closed belt

conveyor

Coal silo

APEC Coal


IEE

JAPAN

Closed Silos to Make Powder Coal

Closed Coal

Silo System

APEC Coal


IEE

JAPAN

Measures for Pollution Abatement

and Waste Utilization in Coal Power

• Closed coal belt conveyor system from ship

berth to silo

• Closed coal silo system to make fine powder

coal blown into boiler directly

• Higher efficiency of power generation

• Powerful desulfurization and denitrification

units for flue-gas

• Utilization of wastes such as ash and gypsum

as materials for cement and plaster boards

APEC Coal


IEE

JAPAN

Coal Power Plant Constructed

near the National Park

APEC Coal


IEE

JAPAN

Coal’s Position in Environment

issues

• For OECD countries

u Try to decrease coal demand or introduce

more efficient coal technology economically

to against Global Warming Policy target

• For DCs

u Try to decrease the regional environment

impact and GHGs emissions by coal burning

through using an economically efficient way

to keep economic growth

APEC Coal


IEE

JAPAN

Energy v.s. Environment

What is the solution

• For OECD countries

u Keeping energy supply mix for energy security

u Seeking the lower cost option to meet Kyoto

Target

• For DCs

u Keeping low price energy supply, and…

u How to introduce the technologies to decrease

environmental impact and keep economic

growth

CO2 problem only is remaining unsolved

APEC Coal


IEE

JAPAN

Kyoto Protocol

• Developed economies (Annex B) are assumed to

have accepted obligations to limit GHGs

emissions

• The Protocol incorporates “flexible mechanism;

Kyoto Mechanism” to achieve the target at

lowest cost in the world

• The Protocol prepares 3 flexible mechanisms,

Emissions Trading, , Joint Implementation(JI

JI),

and Clean Development Mechanism(CDM

CDM)

APEC Coal


IEE

JAPAN

Kyoto Mechanism (1)

• Market-Based mechanism

• Annex B economies and firms can trade

“GHGs

credits” each other, and…..

• They can get credits through investment in

developing countries, and therefore…

• They can exchange these for domestic permits

• It would result in an equal reduction by

domestic action

APEC Coal


IEE

JAPAN

Kyoto Mechanism (2)

Performer A

Provider of Emission Credit

The actual amount

of emissions below

the emission quota

Excess

Developing

countries with no

emission quota

Management Control

Certifying Body

The Kyoto Mechanism

Emission

Credit

Performer B

Buyer of Emission Credit

The actual amount

of emissions above

the emission quota

•{

The amount of

emissions to be

reduced

Attainment of

Emission Target

APEC Coal


IEE

JAPAN

Why Kyoto Mechanism is

Marginal Cost

(1990 US$/t-C)

250

200

150

100

50

0

0.36

necessary

0.28

Marginal Cost

Total Cost

0.17 0.18

Total Cost per GDP(%)

0.30

148.7 174.2 165.4 203.1 120.8

USA Canada EU Japan AU, NZ

•¦AU: Australia, NZ: New Zealand

(Source) European Commission, "Economic Foundations for Energy Policy"

December 1999

0.4

0.3

0.2

0.1

0

APEC Coal


IEE

JAPAN

How Would a Mechanism Work

- Emissions trading-

International Community

Treaty Enforcement (Assigned Amount)

Buyer Country

Government

Domestic Enforcement

•ECommand and Control

•ENational Emissions Trading

•EOthers

Buyer Company

Seller Country

Government

Domestic Enforcement

Seller Company

Treaty Direct and Indirect Enforcement Routes

Potential Trading Relationships

Source: Resources for the Future, correct by author

APEC Coal


IEE

JAPAN

How Would a Mechanism Work

Buyer Country

Government

Deveroping

Country

- CDM-

Domestic Enforcement

Buyer Company

International Community

Certification

Government

Company

Projects

GHGs

Reduction

Credits

Investment, Fund

Credits Transfer

APEC Coal


IEE

JAPAN

Merit for Using Kyoto

Mechanism

• For Annex B Economies (Firms)

u Developing achievement option

u Decreasing abatement cost

• For developing economies

u Create Investment and Technology Transfer

u Efficient way for Environment Conservation

• For the Global Climate Change Target

u Meet the Kyoto Target at the lowest possible

cost

APEC Coal


IEE

JAPAN

How To Use in Coal Market

• Developed Economies (Firms) invest in coal

related project with efficient coal technology

that they have, if they have technological

advantage

• Get credits through JI or CDM project (not

coal related), and construct facility in their

economy in same period (Carbon Off-Set)

• Purchase coal with credits that is created by

coal supplier’s s investment for carbon reduction

(domestic action, JI, CDM)

• Others

APEC Coal


IEE

JAPAN

Trial Example on Combination of

GHG Reduction Credit with Coal

Tohoku Electric Power Co.

•Buying coal

•Cooperating CO2 reduction projects

•Getting CO2 reduction credits

Power Coal Co.

•Selling coal

•Project on methane recovery

and use: 1.6 million t-CO2

•Getting CO2 reduction credits

Centennial Coal Co.

•Selling coal

•Project on Afforestation:

25,000 t-CO2

•Getting CO2 reduction credits

Note: Announced on October 31, 2001

APEC Coal


IEE

JAPAN

Kyoto Mechanism is Uncertain

• The Kyoto Protocol come into effect

When

• What is final scheme of Kyoto Mechanism

• How much the future credit price in the

world trading market

• What is introduced as domestic measures

But we should do action to prepare for

the Future !

APEC Coal


IEE

JAPAN

Importance of Early Action

• Seeking “lower” project and examination for

future trading price

• Learning for operation (baseline, negotiation

with partner economy, , firm, and adaptation for

international scheme)

• Discussion about domestic measures and

internal/international trading scheme

• Examination for business strategy (new market,

risk hedge strategy)

• Discussion and making a relationship with

partner economy (firm)

APEC Coal


COAL IN SUSTAINABLE

SOCIETY

Dr Louis Wibberley

Manager Environment & Sustainability

BHP Billiton

Australia


Coal in a Sustainable Society

Louis Wibberley

Manager Environment and Sustainability, BHP Billiton Technology

Abstract

The greenhouse issue has focused attention on coal’s environmental credentials, and its role in the

transition to a sustainable society. However, it is important to recognize that most of the world’s

people still depend on coal for most of their power and steel.

LCA and other systems analysis tools are being used increasingly to quantify and identify

improvement options throughout energy chains. In the next 10-15 years it is likely that GGEs

associated with steel production and electricity generation will decrease by 30% per unit of output,

both through incremental and new technologies – the technology is either in place, or in the final

stages of development.

For both electricity and steel production, there are important synergies with the cement industry, and

industrial ecology (by-products of one industry being used as inputs to another) can lead to synergies

with other industries.

In addition to considering greenhouse gas emissions from coals use, issues such as fresh water

consumption, particulates and arsenic/fluoride emissions (human health impacts) need to be

considered.

Fresh water consumption for electricity generation (approximately 4 t/t of coal), will reduce as the

efficiency of coal utilisation increases: there is a virtuous cycle – improved efficiency reduces GGE,

water consumption, particulates, SO X and NO X . Human health impacts, usually associated with direct

coal use for cooking and heating in homes in developing economies, can be overcome by (for

example) increased availability of electricity.

The comparison of energy technologies, to enable society to evaluate options on an objective basis,

requires values to be placed on externalities. In addition to LCA-type approaches, the EU have

developed a methodology which costs the impacts associated with GGE, NO X , SO X and suspended

particulates for energy production systems (note that fresh water use was not included). Since

technology exists to substantially reduce NO X , SO X and suspended particulates, GGE will remain as

the major strategic issue for coal use.

While the magnitude of the role of coal in the transition to a sustainable society can be debated, there

can be no doubt that coal will continue to be a major source of energy and reductant. However,

society will require that coal is used more efficiently and with less impacts. The many opportunities

for improvement through the coal chain can only be addressed by participants working cooperatively.

There is also scope to couple renewables with coal, and overcome the separation that has limited

synergies in R&D and the effectiveness of commercial operations.

The availability of coal, its ease of storage and cost advantages, underpin energy security in many

economies. The economic benefits of coal use will help fund the transition to a less carbon intensive

society, whether by increased coal use efficiency, increased use of renewables, or sequestration, or a

combination of all of these. The many improvement options for coal can also give low cost CO 2

abatement.

Life with coal will continue to pose challenges, while at the same time providing energy security,

supporting economic development and underpinning the development of renewables.


1

Coal in a sustainable society

Louis Wibberley


Coal facts 2001

2Coal in a Sustainable Society

“Most of the world’s people depend on coal for most of their power”

% coal fired power

90

80

70

60

50

40

30

20

10

0

China

Indian

subcontinent

Sources: IEA 1998, United Nations 1999

Other Asia (incl Australia)

North America

Africa

Europe

Japan

1 2 3 4 5

Population (billions)

South

America


Context

3Coal in a Sustainable Society

! Coal faces significant challenges …

– environmental, political and community perceptions

– negativity towards coal is based on superficial “burner tip”

comparisons (a poor basis for policy formulation)

– but … policy dilemma - how to meet the development needs of the

world in a sustainable, affordable manner

! ... but coal will have a key role to play

– coal is expected to underpin future energy demand (large reserves,

diversity of supply, stability of price, ease of storage)

– although coal consumption is expected to increase, the proportion of

the total energy is expected to decrease

– renewables need a base load energy source


Value chain assessment

4Coal in a Sustainable Society

! Requires systems analysis, from coal in the ground through

to waste disposal

– life cycle analysis (LCA) and ExternE are supporting tools

! LCA

– starts with an inventory of inputs /outputs which provides data for

assessing impacts

– useful for comparing/improving processes

– leads to an understanding of process chain and technology

! Another approach is to value in $ (eg ExternE)

– extension of LCA impact assessment

– total costs of environmental impacts on a regional basis

– understanding of overall economics of options

! Both approaches have limitations and continue to be

developed


5

Iron and steelmaking

1


Historical perspective – iron and steel

6Coal in a Sustainable Society

! Impressive process improvements have been made by the

steel industry over time, by both breakthrough and

incremental technology development

CO 2 t/t steel bar

1000

100

10

1

0

0

Low bloomery (charcoal)

Liquid iron (charcoal BF)

Wet puddling

Coke BF

Hot blast BF

Bessemer steelmaking

Open hearth

BOS

Continuous casting

Recycling

Integration


New technology

500 1000 1500 2000

Renewables

Year


7Coal in a Sustainable Society

Steel GGE (t CO 2 -e/t cast steel)

! a systems or holistic approach is required

Emissions

to air

Resources

in ground

All processes

involved in the

production of cast

steel

Emissions

to land

Emissions

to water

Slag

(cement credit)

Functional unit:

1 t steel

Offgas

(electricity credit)


Displacement credits - slags

8Coal in a Sustainable Society

a) BF slag processing system

(basis 3,500 kg hot metal)

b) Cement system

Limestone and

shale quarrying

Blast furnace

1,020kg CO 2

Slag grinding

Cement plant

(includes clinker grinding)

60 kg CO 2

1,000kg

BF slag cement

GGE 60kg CO2-e

(equivalent to 1,000kg

of Portland cement)

Portland cement

GGE 1,020 kg CO 2

-e

1,000kg

No technical

or economic

issues

Often limited

by attitudes

A product

stewardship

issue for both

coal and

steel


Displacement credits - offgases

9Coal in a Sustainable Society

! Almost entirely utilised for both heating and electricity

generation – but the displacement credit for electricity is

highly dependent on the efficiency and energy mix of

the grid

– low CV gas (eg BF gas) can give a negative credit (ie worse)

when used for electricity generation

– best for high CV gas used in combined cycle gas turbines

! Incorrect assumptions, especially for some of the new

ironmaking technologies which generate considerably

more offgases can give highly misleading GGE values


Steel GGE (t CO 2 -e/t cast steel)

Coal in a Sustainable Society

BF - BOS

Corex - BOS

Midrex - EAF

New technology

0.0 1.0 2.0 3.0 4.0 5.0

Net GGE

Electricity credit

Existing

Gas based DRI

Emerging coal

technology

Slag credit

10


Blast furnace only one source of GGE

Coal in a Sustainable Society

11

coal supply

coke ovens

sinter plant

hot blast

gross GGE

net GGE

blast furnace

power plant

BOS

electricity

aluminium

transport

other

0.0 0.5 1.0 1.5 2.0 2.5 3.0

GGE (t CO 2 -e /t cast steel)

by-products

slag credit

electricity credit


Coal in a Sustainable Society

12

Improvement opportunities

100

80

60

40

20

Reduction in GGE (%)

Incremental

Slag Credits

CBM

Biomass

Scrap

New technology

Integration


Coal bed methane (CBM)

Coal in a Sustainable Society

13

Turkey

Russia

USA

China

Australia

India

Indonesia

0 5 10 15 20 25

Methane content (Nm 3 /t)

Underground

coal mine CBM

Ventilation air

(MVA)

• World total 30 Mtpa

only 5% utilisation

• ~50% as MVA for underground

mines

• biggest GGE benefit from

oxidation, power gives small

additional benefit

Pre-drainage methane

(35 - 90% CH 4 )

MVA

(0.2 - 0.8 % CH 4 )


CBM utilisation at Appin & Tower

Coal in a Sustainable Society

! 94MWe using 1MW e

gas engines

! 160kt/a CH 4 utilised

(pre-drainage gas,

some MVA used as

combustion air)

! 3Mt CO 2 -e avoided

annually

14


MVA oxidation at Appin

Coal in a Sustainable Society

! MEGTEC 340kW

Vocsidizer unit

- supported by

ACARP

! Combusts

methane in MVA

– 4000Nm 3 /h

! Stage 2 to

include power

generation

– GGAP funding

15


Charcoal – limited applicability

Coal in a Sustainable Society

16

Charcoal trials at Corrimal

Cost $350-500/t

Niche markets already economic

(eg recarburiser is 10-20kt/a in Aust)

Biomass to generate electricity is a

more effective approach

- less transport

- more flexibility in biomass type


Electricity generation

Coal in a Sustainable Society

17


Coal in a Sustainable Society

18

Historical perspective

Faraday

generates

electricity

1882 Reciprocating

steam engines

1884 Steam turbine

introduced

Universal use of steam turbine

Increasing scale 10 - 50,000kW

9

1920-35 Increased scale, superheat,

water wall furnaces, suspension firing

8

7

1970s Larger capacity, unified

designs

6

Clean coal technologies

IGCC, USC, integration,

synergistic renewables

5

4

3

GGE (t/MWh)

2

1

0

1800 1850 1900 1950 2000 2050

Increasing scale

Superheat & pressure


Electricity GGE (t CO 2 -e/MWh)

Coal in a Sustainable Society

19

0.0 0.2 0.4 0.6 0.8 1.0

Conventional

Coal

NG C-C

LNG C-C

Range

Range

Gas

IGCC

Future coal

Clean coal

Hydro

Range

Photovoltaic

Renewables

Wind, biomass

Nuclear

Net GGE Ash Credit


Electricity GGE (t CO 2 -e/MWh)

Coal in a Sustainable Society

0.0 0.2 0.4 0.6 0.8 1.0

Conventional

Coal

NG C-C

LNG C-C

Range

Range

Gas

IGCC

Future coal

Clean coal

Hydro

Range

Photovoltaic

Renewables

Wind, biomass

Nuclear

Net GGE Ash Credit

20


Coal in a Sustainable Society

21

Improvement opportunities

100

80

60

40

20

Basis: 36% NTE

Reduction in GGE (%)

Incremental

Flyash use

CBM

Biomass

Solar-thermal

Supercritical

Ultrasupercritical

Emerging

Combined


Reduction options

Coal in a Sustainable Society

Option

Incremental improvements

Replacement

Old coal with new

Supercritical pf

Ultrasupercritical pf (now)

Ultrasupercritical pf (future)

Emerging IGCC etc

Flyash to cement

Biomass-coal

Solar-coal

Change in

efficiency*

36→38

26→40

36→40

36→42

36→50

36→50

GGE reduction

(%)

5

25

10

15

30

30

5-7

5-15

10

22

* gross, sent out


Synergies with renewables

Coal in a Sustainable Society

23

Biomass co-firing

35% biomass conversion

efficiency (20% for dedicated)

Solar thermal

30-40% solar conversion

efficiency (13% for PV)

Coal can promote uptake and efficient use of renewables

Coupling of renewables and fossil energy research is essential


Biomass-coal generation

Coal in a Sustainable Society

24

! Guadaloupe, Reunion and Mauritius have installed 6 X 70 MWe

dual fuel power stations:

– bagasse (6 month season)

– coal (when bagasse unavailable)

! Provide electricity throughout year, while maximising use of

renewable energy (biomass)

– economic and social benefits

– enables more efficient plants to be built

Source: Good News from Coal, WCI, Nov 1999


Solar-coal generation

Coal in a Sustainable Society

! Several technologies

have been proposed

– 130 MW e per km 2

! Lowest cost routes to

solar electricity

– A$80/MWh @

100MW e

! Demonstration plant

of 3MW e (av) under

consideration

25


CDM - extending the value chain

Coal in a Sustainable Society

CBM/MVA

! Growing importance in life

with coal

– many opportunities for the

coal industry

– need to build mechanisms to

identify and progress

Repowering

26

Co-firing biomass


Other issues

Coal in a Sustainable Society

Time Magazine July 2001

! Small scale direct use of

fuels is causing major

problems in some parts of

the World

– As/F in China

– particulates in RSA/China

– Mine safety issues

– adverse perceptions

of life with coal

27


Coal in a Sustainable Society

28

Direct use of solid fuels - TSP

4

3

2

1

0

! Particulates are a major

health issue in South

Africa and China

– cooking and heating

! Powering with grid

electricity the solution

Relative TSP for cooking

– similar costs in some cases

Electricity

LPG

Kerosene

Wood

Coal

250

Charcoal

200

150

100

Relative cost

50

0

Kerosene

Electricity

Wood

LPG

Charcoal

Coal


Water consumption (indicative)

Coal in a Sustainable Society

Product/service

Coal fired power (m 3 /MWh e )

Steel (m 3 /t cast steel)

Wood (m 3 /m 3 )

Wheat (m 3 /t)

Rice (m 3 /t)

Household (m 3 /person/year)

Water consumption

2

2.5

400

1,000

1,500

! Australians need 1 million litres of fresh water per

person per year (ABS 1996-97)

– includes industry and food production

! Life with coal will require increased attention to water

issues - both consumption and contamination

70

29


Power generation – water use

Coal in a Sustainable Society

! Water consumption for power generation depends upon the

cooling technology used and the efficiency of the conversion

of steam to electricity in the turbine

Majuba power station in South Africa

Units 1-3 (dry cooling)

Units 4-6 (wet cooling)

Water

consumption

(m 3 /MWh)

0.2-0.4

2.0-2.5

Efficiency

(%)

~33

~37

Source: African Energy Vol.1, No.3, 1999

30


Coal in a Sustainable Society

31

Power generation – water use history

10

8

6

4

2

0

1880 1900 1920 1940 1960 1980 2000 2020 2040

Cooling water (t/MWh sent out)

Increasing turbine efficiency


ExternE – costing of externalities

Coal in a Sustainable Society

! Started as EC and USA Fuel Cycles Study in 1991

– evaluation of external costs associated with fuel chains

! 1993-1995, continued as Externe project

– 40 European institutes (9 countries)

– USA scientists involved

! Methodology developed for quantifying

environmental and social impacts and costs

associated with production and consumption of

energy

– used to evaluate external costs of

incremental use of different fuel cycles

in EU countries

32


ExternE – costing of externalities

Coal in a Sustainable Society

! Started as EC and USA Fuel Cycles Study in 1991

– evaluation of external costs associated with fuel chains

! 1993-1995, continued as Externe project

– 40 European institutes (9 countries)

– USA scientists involved

! Methodology developed for quantifying

environmental and social impacts and costs

associated with production and consumption of

energy

– used to evaluate external costs of

incremental use of different fuel cycles

in EU countries

33


Coal in a Sustainable Society

ExternE for coal-based electricity

Europe (mECU/kWh)

Economy

UK

Germany

Sweden

NO X

6.1

6.3

0.079

SO X

10.5

2.9

0.366

YOLL

TSP

+Other

2.9

1.2

0.036

YOLL = Years of life lost converted to economic terms

Total

19.5

10.4

0.481

Global

warming

GHG

mid 3%

15

14.3

13.2

All

other

7.5

5

4.419

Other = includes morbidity costs of TSP, SOx & NOx, and accidents ( accidents minor contributor)

Total

42

29

18.1

Comments

UK deep mine, PF, ESP, FGD

Low NO X

, no SCR

DENOX, FGD

SCR for NO X

> 90% reduction,

FGD for SO X

> 88% reduction,

Electric filter for PM > 99%

reduction, cogeneration

All Other = cost of impacting crops, ecosystems, materials, noise, aquatic systems & aesthetics

Mid 3% GHG: A discount rate is applied to future impacts of global warming events

34

EUR 18528 – ExternE- Externalities of Energy

Vol. 10 National Implementation


Final remarks

Coal in a Sustainable Society

! Many opportunities for improvement throughout the coal

chain, for both iron and steel, and electricity generation

– a systems approach is required to identify these

– many include product stewardship - which provides opportunities for

all participants

! Substantial improvements are available through

“incremental” changes to “conventional pf” technologies and

new technologies

– by 2015, improvements in efficiency will enable reductions in

resource consumption, GGE and water use by 30%

! Coal will underpin the use of renewables for electricity

generation

– need to couple renewables and fossil fuel R & D

! CDM

– opportunities along the value chain

35


Coal in a Sustainable Society

Final remarks

Life with coal will

continue to pose

challenges, while at the

same time providing

energy security,

supporting economic

development and

underpinning the

development of

renewables

36 36


CO 2 EMMISSION AND CLEAN

DEVELOPMENT MECHANISM

PROJECTS

Ms Lucila Q Maralit

OIC-Assistant Director

Energy Resource Development Bureau

Department of Energy (DOE)

Philippines


ABSTRACT

As a commitment to the United Nations Framework Convention on Climate Change

(UNFCC) which was ratified by the Philippines on 2 August 1994, the economy shall

adopt mitigation projects on climate change and develop adaptation strategies that

promote sustainable development.

Based on the 1994 national greenhouse gas emission inventory, the energy sector has the

most remarkable carbon dioxide (CO 2 ) emission contribution in the atmosphere

equivalent to 49% share in the total accounting. To reduce environmental impacts

emanating from the energy sector, the Department has identified two programs, namely:

1) promoting cleaner fuels including new and renewable energy; and, 2) energy

conservation and efficiency.

At present, the Philippines is proposing a project entitled, “Formulation/Establishment of

the Philippine Clean Development Mechanism (CDM) Operational Framework” which

would formulate or establish an operational framework within the economy’s context on

the implementation of CDM within the period October 2001 to September 2003.

The Philippines has identified major projects to be financed by the CDM. These are the

utilization of new and renewable energy sources in both on-and off-grid areas and

efficiency in the supply side and demand side. For its part, the Philippine government,

has been creating enabling conditions to support CDM implementation and climate

change concerns as a whole.


INTRODUCTION

The Philippines signed the United Nations Framework Convention on Climate Change on

June 12, 1992. The Philippine Senate subsequently ratified the Convention on August 2,

1994.

Since then, the Philippines has been actively involved in the negotiations to bring the

economy’s climate change concerns in the Conference of the Parties (COP). In the Third

Conference of the Parties (COP-3), held in Kyoto, Japan, the economy, as member of the

ong>Groupong> of 77 (G77), had actively pushed for a legally binding Protocol under which

industrialized economies will reduce their overall emission of six greenhouse gases

(GHGs) by at least five percent below the 1990 levels between 2008 and 2012. The

Protocol, dubbed as “Kyoto Protocol,” established three (3) Mechanisms that have the

potential to reduce the cost of meeting Kyoto objectives. These are international

emissions trading, joint implementation between developed economies and clean

development mechanisms (CDM) between developed and developing economies.

On the basis of the recently concluded Conference of Party (COP) 6, part II meeting in

Bonn, Germany, expectation is high that the Kyoto Protocol will enter into force in 2002.

The celebrated Bonn decision has laid the groundwork for the Protocol’s entry into force

by agreeing to a set of political decisions, mostly concessions to developed economy’s

concerns in complying with GHG reduction, among which included the CDM.

Carbon Dioxide (CO 2 ) Emissions

There are two (2) national greenhouse gas emission inventories conducted in the

Philippines, one in 1990 and the other, in 1994. The first Inventory was initially

undertaken under the U.S. Country Study Program. The 1994 Inventory was done

through the Enabling Activity Project funded by the Global Environment Facility (GEF)

through the United Nations Development Program (UNDP). Comparison between the

1990 and 1994 Inventories can be seen in the preceding table.

In 1994, the Philippines emitted a total equivalent amount of 100,739 kilotons of

carbon dioxide in the atmosphere. This is the combined emission from four (4) sectors,

namely; Energy, Industry, Agriculture and Wastes, minus the net uptake of the Forestry

sector (sink). (Figure 2). Based on the above statistics, the energy sector has the most

remarkable contribution due to its 49% share in the total accounting. This is followed by

agriculture (33%), industry (11%), and wastes (7%).

Within the energy sector, it is further subdivided into seven (7) subsectors (Figure 3).

These are power generation, residential, industries, agriculture, transport, commercial and

fugitive emission. As seen in the table, transport has the highest emission in the

subsector, releasing 15,888 ktons of CO 2 into the atmosphere. This is trailed closely by

power generation, which emitted 15, 508 ktons of CO 2 . Meanwhile, fuel consumption of

the industries came strong at third with 9, 497 ktons of CO 2 emitted.

However, as viewed from the international perspective, the Philippines has

negligible contribution to the world’s emission of CO 2 .


III. Measures taken to Reduce Carbon Dioxide Emission from the Energy Sector in

the Philippines

The Philippine Department of Energy is the agency mandated by law to supervise all

activities related to energy. As such, its primary role is to ensure energy supply

availability to all sectors of the society. In acknowledging its part in discharging carbon

dioxide emissions in the atmosphere, the Department has taken several steps to address

the climate change issue. These are: a) providing a policy framework to address climate

change; b) promoting programs on and increasing use of renewable energy and energy

conservation; c) increasing information, education, and campaign (IEC) programs to all

sectors of the society; and, d) participating in the national committee that handles climate

change negotiations (Inter-Agency Committee on Climate Change-IACCC). In

concretizing these steps, the Department has identified two (2) specific programs that can

be subsumed in the climate change mitigation program. These are programs promoting

cleaner fuels including new and renewable energy, and energy efficiency.

For cleaner fuels, the Philippines is on course in its programmed utilization of natural gas

in 2002. The natural gas will be increasing its present share of power generation mix

from 0.04% to 30.4% next year, displacing much of the coal and oil. Thus between

2001 and 2002, the share of emission from coal shall decrease slightly from 21,850 Gg to

16,670 Gg CO 2 while CO 2 emission from gas shall increase from 91 Gg in 2001 to 6,000

Gg in 2002 (Figure 4) In terms of emission, natural gas emits 40% less N0x, 60% less

CO 2 and virtually no S0x emission as compared to coal. Aside from power generation,

the Department is currently exploring its program on natural gas for transport in the

Philippines. This project, which is supported by the government of New Zealand, aims to

reduce CO 2 and N0x, as well as particulate emission that currently plagues major cities in

the economy.

Meanwhile, new and renewable energy sources have been given much boost with the

signing of the Executive Order No. 462 in December 1997. The E.O. has been designed

to provide for the extraction, harnessing, development and utilization of ocean, solar,

wind (OSW) energy resources and to encourage private sector participation. Of late, a

solar and wind map potential has been completed, and a study on the potential of

generating electricity by ocean thermal, tidal current and wave has been undertaken.

For energy efficiency, the Department has instituted programs for the supply and demand

side. In the supply side, the government has implemented the heat rate improvement for

power plants and system loss reduction in distribution utilities. For the demand side,

aside from setting efficiency standards of energy-intensive appliances, i.e. room air

conditioners, lamp ballasts, refrigerators, etc; the Department also conducts energy audits

of different industrial establishments. Programs in energy efficiency have become more

apparent with the launching of information campaign geared to promote wise and

efficient use of energy. Dubbed as “Power Patrol” and “Road Transport Patrol,” these

twin programs aim to lessen the demand for power and fuel, respectively. Moreover, the

government has also extended financing schemes to support the implementation of

energy conservation projects of industrial and commercial establishments. This foreignfunded

and agency- initiated scheme is called the Technology Transfer for Energy

Management – Demonstration Loan Fund (TTEM-DLF).


The implementation of these programs would result on 4.83 % of the total projected CO 2

emission avoidance for year 2002. There will be an increasing trend of emission

avoidance onwards until 2007, which will register at 5.5 %. Meanwhile the share will

stabilize at approximately 5 % from 2008 to 2011 (Figure 5).

In the past, collaboration with multilateral as well as bilateral donor agencies provided

assistance to the government to determine what mitigation options the government would

implement to curb greenhouse gas emission. The Asia Least-cost Greenhouse Gas

Abatement Strategy (ALGAS), which was funded by the Global Environmental Facility

(GEF) through United Nations Development Programme (UNDP) and executed by the

Asian Development Bank (ADB), was a study of 12 Asian economies, including the

Philippines, of their national emission of GHGs in 1990, projection to 2020 and an

analysis of the mitigation options in different economic sectors. The ALGAS study has

identified the Philippine energy sector as one of the major sources of GHG and has the

greatest potential for mitigation as well (ADB-GEF-UNDP, 1999). In the study of the

energy sector, system loss reduction and heat rate reduction in power generation appear

to be the top mitigation options to abate GHG.

The economy has also been collaborating with the United States government through the

US Agency for International Development (USAID). The project entitled,“ Strategic

Objective Agreement for the Mitigation of Greenhouse Gases in the Philippines (SOAG)

has been formally implemented by Governments of the Philippines and the United States.

Aimed at developing a strategy to offset some of the expected increases in GHG emission

generated by the power sector, the program was concluded in May this year.

At present, the Philippines is proposing a project entitled, “Formulation/Establishment of

the Philippine Clean Development Mechanism (CDM) Operational Framework” which

would formulate or establish an operational framework within the economy’s context on

the implementation of CDM. Funding support is being sought from The Netherlands

Government through the UNDP. The project is expected to develop the framework

within the period of October 2001 to September 2003.

The Clean Development Mechanism

The Clean Development Mechanism (CDM) has been conceived as one of the “flexibility

mechanisms “ within the Kyoto Protocol to the United Nations Framework Convention

on Climate Change. Along with emission trading (ET) and joint implementation (JI),

CDM is intended to lower the cost to industrialized economies, of complying

commitments to limit and reduce emission of GHG. Moreover, CDM is the only

mechanism designed to be undertaken between the Annex-1 and Non Annex-1

economies.

In the Article 12 of the Kyoto Protocol, the purpose of the CDM has been identified. It

envisions to assist developing economies to achieve sustainable development, contribute

to the ultimate goal of the Convention, and, also assist developed economies to achieve

their emission reduction commitments. As can be gleaned in the Article 12, the CDM

projects are specifically purported to beneficiate the developing economies in their

pursuit of economic development while generating “certified emission reduction

(CERs), which the developed economies may use to comply their quantified emission

reduction commitments.


The COP 6, part 2 meeting has specified that energy efficiency and renewable energy can

qualify for CDM, ditto for forest sink. The latter is being negotiated by some developed

economies. Meanwhile, Annex 1 Parties are refrained form using nuclear facilities in the

CDM.

Seeds of CDM in the Philippines

The Philippine energy sector has identified major projects to be financed by the CDM.

Provided that the COP will agree upon the modalities of the CDM implementation, the

Philippine government has been pushing for the environmentally sound adaptation

technologies to address the existing adverse effect of climate change (Muller, 2000). In

mitigation technologies, Department has been focusing its attention to the utilization of

the new and renewable energy sources in both on-and off- grid areas and efficiency in the

supply side and demand side. In detail, the Department has shortlisted some of possible

CDM projects and these are the following:

♦ Wind power

♦ Photovoltaic (PV) solar electric system

♦ Solar thermal electricity

♦ Wave power

♦ Renewable fuels cells

For efficiency projects, it has been identified that some of the existing coal plants have to

be rehabilitated to increase efficiency and/or to utilize less emission-intensive fuels. For

supply side,

♦ Heat rate improvement of coal plants

♦ New electricity generation technologies based on coal with higher efficiencies; i.e.,

pressurized fluidized bed combustion, supercritical steam cycles, and integrated

gasification combined cycles.

On the demand side technologies, CDM projects would include energy-efficient domestic

appliances and industrial plants, i.e., iron and steel, cement, etc.).

The Philippine government, for its part, has also been creating enabling conditions to

support CDM implementation and climate change concerns as a whole. First, baseline

studies as well as formulation of CDM framework implementation are currently being

undertaken. Second, several legislations have been passed to encourage private sector

participation as well as foreign investments. Third, the planning process of the

Department itself is currently under study to improve energy system planning. Last but

not the least, the implementation of the Clean Air Act of 1999, which mandates the use of

pollution control technologies as well as encourages the use of market-based instruments

to abate emission. These local policies and measures can bring multiple benefits as they

reduce environmental impacts on national, regional and international scale.


REFERENCES

Asian Development Bank (ADB) and United Nations Development Programme (UNDP),

Asia Least-cost Greenhouse Gas Abatement Strategy (ALGAS), Manila, Philippines,

June 1999.

Department of Energy (DOE), Philippine Energy Plan Update 2000-2011

Department of Energy (DOE) and The Society for the Advancement of Technology

Management in the Philippines, Ocean, Solar and Wind Energy: Powering the Future in

the Philippines, December 1997.

Department of Environment and Natural Resources (DENR), The Philippines’ Initial

National Communication on Climate Change, December 1999.

Muller, Bernarditas C., The Philippine Approach to the Issues of Development and

Transfer of Technologies under the UNFCCC: The Philippine Approach, A Report

Presented at the UNFCCC Technology Transfer Consultative Asia and the Pacific

Regional Workshop, January 17-19, 2000, Cebu City, Philippines.

United Nations Framework Convention on Climate Change, Convention on Climate

Change, UNEP/IUC, October 1999, available at www.unfccc.de.


Figure 1. Comparison of 1990 and 1994 GHG Emissions in the Philippines

SECTOR

1990 1994

Gg CO 2 % Gg CO 2 %

Energy 38,245 30.9 50,038 49.7

Industry 4,132 3.3 10,603 10.5

Agriculture 0.0 33,130 32.9

Waste 0.0 7,094 7.0

LUCF 81,360 65.8 (126) -0.1

TOTAL 123,737 100.0 100,739 100.0

Figure 2. 1994 Share of GHG Emission from Non-LUCF Sectors of

Energy, Agriculture, Industry and Wastes

Energy

Agriculture

Industry

Waste


Figure 3. 1994 GHG Emission from the Energy Sector

Energy Subsector CO2 Emissions

(ktons)

Transport 15,888

Power Generation 15,508

Industries 9,497

Residential 4,359

Commercial 3,370

Agriculture 1,189

Fugitive Emissions 227

Total 50,038

Source: The Philippines’ Initial National Communication on

Climate Change, December 1999


Figure 4. – Projected CO 2 Emission from Energy

(in GgCO 2 )

2002 – 2011 Philippine Energy Plan Update Energy Mix

180.00

165.00

150.00

135.00

Total

120.00

105.00

90.00

Oil

75.00

60.00

45.00

Nat Gas

30.00

YEAR

COAL

OIL

GEO

NATURAL GAS

TOTAL

2000 15557.23 52622.29 537.56 23.62 68740.69

2001 21589.40 50700.58 451.73 104.62 72846.33

2002 16538.07 50612.60 405.96 6921.51 74478.14

2003 18995.62 50459.79 459.91 6921.51 76836.83

2004 20875.57 56998.22 464.81 7427.72 85766.31

2005 13617.34 57641.87 796.12 10286.09 82341.42

2006 14914.23 60536.00 842.43 10444.70 86737.37

2007 16243.82 65120.31 884.12 11683.22 93931.46

2008 18178.25 69621.27 913.00 13394.19 102106.71

2009 20597.66 74446.37 1012.72 14359.35 110416.10

2010 22450.36 79470.58 1079.47 15955.59 118956.00

2011 21344.19 84601.30 1145.68 38920.11 146011.28

(2002 – 2011 Philippine Energy Plan Update Energy Mix)


Figure 5. Projected CO 2 Avoidance from Energy Efficiency

Projected CO 2 Avoidance from Energy

60

Gg CO 2

('00)

53

45

38

30

23

15

Energy Management

Services

Government Enercon

Program

System Loss

Reduction

Heat Rate

Improvement of

Power Plants

Efficiency/Energy

Labelling &Standard

Demand Side

Management

Total

8

0

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011


PHILIPPINES: CO 2 EMMISSION AND CDM

PROJECTS

by

Ms. Lucila Q. Maralit

OIC-Assistant Director

Energy Resource Development Bureau

Philippine Department of Energy

“8 th Apec Coal Flow Seminar”

Kuala Lumpur, Malaysia

March 4, 2002

1


8 th APEC Coal Flow Seminar March 4, 2002

OUTLINE OF PRESENTATION

I. Introduction

II. Carbon Dioxide Emission

III. Measures to Reduce Carbon Dioxide

Emission from the Energy Sector

IV. Seeds of CDM in the Philippines

2


8 th APEC Coal Flow Seminar March 4, 2002

CLIMATE CHANGE IN THE

PHILIPPINES

4 The Philippines signed the United Nations

Framework Convention on Climate Change

(UNFCCC) on June 12, 1992.

4 The Philippine Senate ratified the Convention on

August 2, 1994.

3


8 th APEC Coal Flow Seminar March 4, 2002

CARBON DIOXIDE

EMISSION

4


8 th APEC Coal Flow Seminar March 4, 2002

CARBON DIOXIDE (CO 2 )EMISSIONS

• GREENHOUSE GAS INVENTORY

1990 – U.S. Country Program

1994 – United Nations Development Program

5


8 th APEC Coal Flow Seminar March 4, 2002

Comparison of 1990 & 1994 CO 2

Emissions

SECTOR

1990 1994

Gg CO 2 % Gg CO 2 %

Energy 38,245 30.9 50,038 49.7

Industry 4,132 3.3 10,603 10.5

Agriculture 0.0 33,130 32.9

Waste 0.0 7,094 7.0

LUCF 81,360 65.8 (126) -0.1

TOTAL 123,737 100.0 100,739 100.0

Sources: The Philippines’ Initial Communication on Climate Change, 1999

6


8 th APEC Coal Flow Seminar March 4, 2002

1994 Share of GHG Emission from Non-LUCF Sectors

of Energy, Agriculture, Industry and Wastes

32.9%

7%

49.6%

10.5%

Energy

Agriculture

Industry

Waste

Source: The Philippines’ Initial Communication on Climate Change, 1999

7


8 th APEC Coal Flow Seminar March 4, 2002

1994 GHG Emmission from the

Energy Sector

Energy Subsector

Co2 Emissions (ktons)

Transport 15,888

Power Generation 15,508

Industries 9,497

Residential 4,359

Commercial 3,370

Agriculture 1,189

Fugitive Emissions 227

Total 50,038

8


8 th APEC Coal Flow Seminar March 4, 2002

GENERAL RESPONSE TO CLIMATE CHANGE

OF PHILDOE

4 PROVIDING POLICY FRAMEWORK TO ADDRESS CLIMATE

CHANGE

4 PROMOTING PROGRAMS AND INCREASED USE

OF RENEWABLE ENERGY AND ENERGY EFFICIENCY

4 INCREASING INFORMATION AND EDUCATION

CAMPAIGN (IEC) PROGRAMS TO ALL SECTORS OF

THE SOCIETY

4 PARTICIPATING IN THE NATIONAL COMMITTEE THAT

HANDLE CLIMATE CHANGE NEGOTIATIONS (IACCCC)

9


8 th APEC Coal Flow Seminar March 4, 2002

SPECIFIC RESPONSE OF PHILDOE TO

CLIMATE CHANGE

• Promote further use of clean energy,

including new and renewable energy

sources

• Increase programs on energy efficiency

10


8 th APEC Coal Flow Seminar March 4, 2002

NATURAL GAS

11


8 th APEC Coal Flow Seminar March 4, 2002

Power Generation Mix, 2002

Base Case: Low GDP

Power Generation Mix, 2011

Base Case: Low GDP

Hydro

13%

Geothermal

17%

Biomass

0%

Others

0%

Oil-Based

6%

Coal

34%

Others

38%

Oil-Based

9%

Coal

21%

Natural Gas

30%

Biomass

0%

Geothermal

9%

Hydro

6%

Natural Gas

17%

Self-sufficiency Level = 63%

Total: 51.6 TWH

Self-sufficiency Level = 72%

Total: 116.2 TWH

12


8 th APEC Coal Flow Seminar March 4, 2002

Projected CO 2 Emission from Energy (in GgCO 2 )

160,000.00

140,000.00

120,000.00

GgCO2

100,000.00

80,000.00

60,000.00

Coal

Oil

Geothermal

Natural Gas

Total

40,000.00

20,000.00

-

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

13


8 th APEC Coal Flow Seminar March 4, 2002

NATURAL GAS

• Malampaya-Gas-to-Power Project

• Natural Gas for Transport Project

14


8 th APEC Coal Flow Seminar March 4, 2002

RENEWABLE ENERGY

Ocean, Solar, Wind (OSW) Project

~ Solar Energy

~ Ocean Thermal Energy

~ Ocean Tidal Current Energy

~ Ocean Wave Energy

~ Wind Energy

15


8 th APEC Coal Flow Seminar March 4, 2002

ENERGY EFFICIENCY PROGRAMS

SUPPLY SIDE

• System Loss Reduction Program for Electric Utilities

• Heat Rate Improvement of Power Plants

DEMAND SIDE

• Vehicle Efficiency Standards and Testing

Energy Audits

Energy Efficiency Information Campaign

• Room Air conditioner (RAC) Energy Standards and

Labeling

• Refrigerator and Freezer Energy Labeling

• Fluorescent Lamp Ballast Energy Labeling

16


8 th APEC Coal Flow Seminar March 4, 2002

ENERGY EFFICIENCY PROGRAMS

INFORMATION, EDUCATION AND CAMPAIGN (IEC)

PROGRAMS

• Power Patrol

• Road Transport Patrol

FINANCING SCHEMES

• Technology Transfer for Energy Management -

Demonstration Loan Fund (TTEM-DLF)

– Financing Energy Conservation Projects

17


8 th APEC Coal Flow Seminar March 4, 2002

Projected CO 2

Emissions Avoidance

from Energy Efficiency, 2002 - 2011

120000

110000

100000

90000

80000

70000

60000

50000

40000

30000

20000

10000

0

2002

2003

2004

2005

2006

Emission Avoidance

Total Emission

2007

2008

2009

2010

2011

18


8 th APEC Coal Flow Seminar March 4, 2002

INTERNATIONAL COOPERATION ON

CLIMATE CHANGE

1 ASIA LEAST-COST GREENHOUSE GAS ABATEMENT

STRATEGY (ALGAS)

• Global Environment Facility (GEF)

• United Nations Development Programme (UNDP)

Asian Development Bank (ADB)

2 STRATEGIC OBJECTIVE FOR THE MITIGATION OF

GREENHOUSE GASES IN THE PHILIPPINES

• US Agency for International Development

19


8 th APEC Coal Flow Seminar March 4, 2002

CLEAN DEVELOPMENT

MECHANISM

20


8 th APEC Coal Flow Seminar March 4, 2002

CLEAN DEVELOPMENT MECHANISM

(CDM)

4 Article 12 of Kyoto Protocol

4 Project-based mechanism to be undertaken by

Annex 1 and Non-Annex 1 Country Parties

4 Purpose:

1. Assist developing countries to achieve sustainable

development;

2. Contribute to the ultimate goal of the Convention; and,

3. Assist developed countries to achieve their emission reduction

commitments.

21


8 th APEC Coal Flow Seminar March 4, 2002

SEEDS OF CDM IN THE

PHILIPPINES

22


8 th APEC Coal Flow Seminar March 4, 2002

POSSIBLE SEEDS OF CDM IN THE

PHILIPPINES

1. ADAPTATION TECHNOLOGIES

4technologies to address adverse effects of climate change

2. MITIGATION TECHNOLOGIES

4 wind power

4photovoltaic (PV) solar electric system

4solar thermal electricity

4wave power

4renewable fuel cells

23


8 th APEC Coal Flow Seminar March 4, 2002

LOCAL POLICIES AND MEASURES TO

SUPPORT CDM

• Baseline Studies as well as formulation of CDM

framework implementation are currently being

undertaken

• Several legislations have been passed to encourage

private participation as well as foreign investments

• The planning process of the Department is currently

under study to improve energy system planning

• The implementation of the Clean Air Act of 1999

24


8 th Apec Coal Flow Seminar March 4, 2002

POSSIBLE SEEDS OF CDM IN THE

PHILIPPINES

2. MITIGATION TECHNOLOGIES, cont’n..

4 Heat rate improvement of coal plant

4 New electricity generation technologies based on coal with higher

efficiencies; i.e., pressurized fluidized bed combustion, integrated

gasification combined cycles, and supercritical steam cycles

25


8 th APEC Coal Flow Seminar March 4, 2002

END

OF

PRESENTATION

Thank You

26


OPENING REMARKS

Mr Hiroshi Yoshida

Executive Director

New Energy and Industrial Technology

Development Organisation (NEDO)

Japan


Opening Address

Day two

The Joint 9 th APEC Clean Fossil Energy Technical Seminar

and 8 th APEC Coal Flow Seminar

Kuala Lumpur, Malaysia

Tuesday March 5, 2002

Hiroshi Yoshida, Executive Director, NEDO

Good morning, distinguished guests, ladies & gentlemen,

I feel highly honored to be here to deliver today’s opening address at the Joint

Clean Fossil Energy Technical and Coal Flow Seminars of APEC.

The TILF Work Shop is also taking place simultaneously with these 2 seminars

for the first time during Coal Week, which will enable us to examine the entire

coal process from upstream to downstream. Putting the utmost emphasis on the

host economy, Malaysia, a full range of important technical, economic and

policy issues on coal in APEC economies will be discussed this week.

These seminars were, at first, scheduled to hold at last year and then extended

due to the impacts from the September 11 terrorist attacks on America and

uncertainties regarding events that might transpire after the attacks. At this

moment, I would like to express my thanks for efforts to hold the seminars by

the host economy, Malaysia, all of speakers and staffs.

The broad theme for this year’s Coal Week is “Coal in Sustainable Development

in the 21 st Century”, which I believe is most appropriate considering the various

challenges we face at the moment in pursuing coal utilization opportunities.

Topics in today’s first session, Session-4, will address coal upstream, while the

rest will be on the downstream of highly professional Clean Coal Technologies.

Actually, I am personally responsible for coal downstream at NEDO, so today’s


topics are at the center of my interest.

Although opinions differ about the Kyoto Mechanism even among advanced

economies, no one can deny the global necessity of stopping global warning.

Aside from continual progress being made in efficiency, we know that it is

technically possible to capture CO2 to the point of little or no release to the

atmosphere. So, I am confident that in the long term global warming issues will

be effectively resolved.

I hope all the participants, after returning to their respective workplace, will

continue implementing structures to ensure that coal contributes to an improved

energy mix and achieves higher environmental standards toward sustainable

development in the 21 st Century.

Thank you for your very kind attention.


SESSION 4:

The Role of Coal in

South East Asia

Chair: Haji Abdul Hadi Deros

Vice President (Generation)

Tenaga Nasional Berhad

Malaysia


EXPORT AND DOMESTIC

USE

Dr Boni Siahaan

Deputy Assistant for Mining and Energy Business

Ministry of State Owned Enterprises

Indonesia


EXPORT AND DOMESTIC USE

presented by:

Dr Boni Siahaan

Head of Subdirectorate of Investment and Logistics

Directorate general of Geology and Mineral Resources

Directorate of Mineral and Coal Enterprises

Indonesia

ABSTRACT

This paper describes the development of Indonesia’s coal mining industry, which rapid

development has been supported by advantages of Indonesia coal such as relatively good

quality of coal and its geographic proximity to Asian markets.

Although the export market underwent rapid development, domestic market absorption

need to be improved. On the other hand, factors such as implementation of regional

authority need to be addressed carefully in order to give more certainty to the coal

mining industry.


A P E C

Dr. Boni Siahaan

Directorate of Mineral and Coal Enterprises

Directorate General of Geology and Mineral Resources

8 th APEC Coal Flow Seminar

Kuala Lumpur, 4 - 8 March 2002

Malaysia


ADVANTAGES OF INDONESIA’S COAL INDUSTRY

ý

ý

Indonesia’s coal industry has access to extensive

resources that are generally have low extraction costs,

Indonesia coal quality are characterized by relatively low

sulfur and ash contents,

ý

Port capacity in Indonesia remains abundant and

can be readily expanded to meet future increases

in demand,

ý

Indonesian coals have competitive price in accordance

with market forces and its geographic proximity to Asian

markets,

ý

In the future many of Indonesia’s coal growth will come

from sub-bituminous coal developments which are easily

accessible and have relatively low cost structure

associated with them.


ý

THE COAL MINING INDUSTRY PROVIDED DIRECT

EMPLOYMENT FOR 43,418 PEOPLE (261 OF WHOM ARE

EXPATRIATES);

ý

CUMULATIVE INVESTMENT BY CONTRACTOR COMPANIES

GENERATIONS 1, 2, AND 3 : FROM 1982 US $3,136,284, 316.08

AND Rp.1,949,429,007,731.04;

ý

STATE REVENUE (TAX AND NON - TAX) FROM GENERATIONS

1,2, AND 3 : US$ 101,025,663.36 AND Rp. 1,058,162,644,265.65;

ý

A SIGNIFICANT CONTRIBUTION TO INDONESIA’S BALANCE OF

PAYMENTS, IN EXCEES OF US$1 BILLION FROM EXPORT

EARNINGS AND DOMESTIC SALES.


Figure 2:

Shares of domestic coal

consumption by major

consumers, 1995 and

2000

1995(9.21 MT)

Others

4%

2000 (20,54 MT)

Cement Plant

26%

Others

18%

Electricity

70%

Cement Plant

18%

Electricity

64%


ý In line with General Policy in the Energy

Sector (KUBE);

ý The policy comprises :-

• Exploitation

• Investment and coal undertaking

• Level of production

• Pricing

• Environment

• Infrastructure


Figure 3:

1995 (31.32 MT)

Coal export pattern,

1995 and 2000

CHILE

3%

OTHERS

13%

JAPAN

27%

2000 (57.46 MT)

SPAIN

4%

NETHERLAND

4%

INDIA

4%

USA

2%

SPAIN

5%

NETHERLAND

4%

INDIA

4% THAILAND

3%

PHILLIPINES

5%

MALAYSIA

5%

CHILE

2%

S.KOREA

8%

OTHERS

10%

HONGKONG

5%

JAPAN

23%

TAIWAN

24%

THAILAND

4%

MALAYSIA

5%

S.KOREA

6%

HONGKONG

12%

TAIWAN

18%


ý Business and problem risks;

ý Impact of implementation of regional

autonomy (Laws No. 22 and 29 of 1999);

ý Issuance of (Government Regulation No.

144 of 2000).


Year Electricity Cement Other Sub-total Export Total

Million tons

2000 15.2 3.6 3.6 22.4 57.4 79.8

2005 27.8 4.5 3.8 36.1 73.5 109.6

2010 39.1 5.7 4.8 49.6 81.7 131.3

2015 55.1 7.2 6.0 68.3 86.0 154.3

2020 77.6 9.1 7.6 94.3 89.0 183.3


ý

Coal demand in Asia into midterm is still rising

although stricter environmental concerns may lead

to the lower sulfur and ash contents to be favoured

by utilities in the future. Improved technology will

give more room for lower quality coal utilization;

ý

Considering potentiality of Indonesia coal mining

industry and ever increasing demand of domestic

and export markets, Indonesia will be poised to

maintain its position as stable coal producer and

exporter, although in longer term capacity increase

in Indonesia may be lower than before.


COAL AND NATURAL GAS

IN THE FUTURE

Mr Tran Van My

Deputy Manager General

Division for International Cooperation

& Development Project

Institute of Mining Science and Technology (IMSAT)

VINACOAL

Vietnam


Coal and Natural Gas in the Future

(The Important Role of Coal and Natural Gas in Vietnam)

presented by: Mr Tran Van My

Deputy General Manager General

Division for International Cooperation and Development Project

Institute of Mining, Science and Technology (IMSAT)

VINACOAL - VIETNAM

Abstract

Vietnam energy resource has different features in three regions of the economy:

Northern, Central and Southern areas. So the high potential of hydropower and coal

reserves are mainly found in the Northern area, small hydropower and diesel power

generation are mainly seen in the Central area, and petroleum and gas resource seem

to be rich in the Southern area.

Coal and natural gas are the important economic sectors of Vietnam. Coal and

gas, at present as well as in the future will be supplied to power generation, cement

industry, other industries and for services, household use.

I. present situation of coal and natural gas

I.1. Coal potential

Vietnam coal which has been exploited for over 100 years since 1883 in Dong Trieu - Quang

Ninh province is one of the oldest industries in Vietnam with many different kinds, and

distributed as follows:

• Anthracite coal is mainly found in Quang Ninh province, the North of Vietnam, with the

reserve of about 3.5 billion tons down to the level -300m (below the sea level) and over

10 billion tons from -300m to -1000m level. Its calorific value is from 6000 to 8000

kcal/kg and the sulfur content of less than 1%.

• Lignite coal has been found in the Red River Delta with the forecasted reserve of about

36 billion tons and at deeper level (2000m) 240 billion tons with the calorific value of

5,000 to 6,000 kcal/kg, sulfur and volatile content of 5 % and 30% respectively. It is

suitable for power generation.

• Peat coal is distributed in many places especially in the Cuu Long River Delta of the

South Vietnam and in the North part of the economy with the reserve of about 6 billion

tons this kind of coal is good for making fertilizer and household fuel.

• Fat coal is distributed in Thai Nguyen and Nghe An provinces with small reserve. The

annual production is less than 100.000 tons and it is only suitable for metallurgy.

In 1999, the coal production is about 11 million tons, of which 3.2 million tons is exported 65%

of coal production is exploited by open pit mining method and the rest underground mining

method. After 2010, the balance in coal exploitation using the two above mentioned methods


will be achieved (50/50). After 2020, the coal production from underground mines will increase

to about 70-80% of total coal production.

At the underground coal mines, the developing activities have always been carried out by using

drifts and in some mines, inclined and vertical shafts. The longwall advancing on strike method

is used and the specific mining technology should be used for thick and steep coal seams.

Mines are mainly supported by using timber sets, metallic linings or reinforced concrete linings.

At present, in some mines the hydraulic single props and hydraulic props with sliding beams are

used for support.

Coal reserve, characteristic and supply for Vietnam economic sectors are shown in Table 1, 2

and 3.

I.2. Gas potential

Gas potential is concentrated in two South Con Son basins in the Southern continental shelf

accounting for 40%, and Red river basin located in Northern shelf, stretching from Tonkin gulf

to the Mid-central area accounting for 30%. Total gas reserve which is exploitable is over 1.200

billion m 3 of which about 1/3 has been proven. (Table 4)

Gas field reserves are at average level. Up to now, the ever-largest gas field has been

discovered with hydrrocacbua volume of 75 billion m 3 but its carbonic content is very high

(70-80%). The ever-biggest clean gas field with an exploitable reserve of 60 billion m 3 was

discovered in the South Con Son basin. In the future, it is expected to find natural gas fields

with reserve less than 32 billion m 3 . Associated gas reserve of each oil field is less than 16

billion m 3 .

According to evaluations, Vietnam oil exploitable reserve is around 4 billion barrels

(approximately 500 million tons) in that case, average gas reserve may reach 1.200 Billion m 3

equivalent to 7,0 billion barrels (approximately 900 million tons). Therefore, it is evaluated that

Vietnam gas reserve with 1.200 billion m 3 is much than oil reserve (nearly double), so Vietnam

is considered a good gas potential compared to other regional economies. For example,

Thailand’s gas reserve is evaluated at about 980 billion m 3 , Malaysia and Australia’s gas

reserve are 2.400 and 2.200 billion m 3 respectively. (Gas of Bachho field and Cuulong field is

associated and clean gas with very low content of H 2 S and CO 2 content is less than 2%. Gas of

the South Conson basin is natural, clean, of low H 2 S content, and CO 2 content is less than 5%).

Therefore, Vietnam has big gas and oil potential resource which can be exploited including:

780 million m 3 of oil and 160 billion m 3 of associated gas, 1.130 billion m 3 of natural gas and

200 million m 3 of condesat. The South Con Son basin, Con Son basin, Cuu Long basin, Malay-

Tho Chu basin and Red River basin are main oil-gas basins which are being explored and

exploited. According to recent assessment, there is about 90% of total oil and gas reserve in the

above basins. Total natural gas reserve is many times bigger than associated gas reserve, it

occupies approximately 90% of the total gas reserve. By 2010, it is forecasted to discover 80%

of associated gas reserve and 60% of natural gas reserve. Total exploitable gas reserve is

approximately 720 billion m 3 , including 625 billion m 3 of natural gas and 95 billion m 3 of

associated gas. The exploitation potential of the four basins: Cuu Long, the south Con Son,

Malay-Tho Chu and Song Hong is high, it can reach 30 billion m 3 per year by 2010, especially

the two basins Cuu Long and South Con Son of about 15 billion m 3 . Based on the forecast for

domestic market demand and export, Vietnam has three alternatives of supply as belows:

- Low case: about 5 billion m 3 per year (domestic market)

- Average case: about 7 billion m 3 per year (domestic market)

- High case: more than 17 billion m 3 per year (including export)


II.

The important role of Coal and Gas in Vietnam energy balance

II. I. Present situation of power generation

According to the Master Plan of Power Generation Development, in the coming years, the

power sector must be developed rapidly to meet the demand of the economy. Power generation

capacity was 24 billion kWh in 1999. By 2001, power generation capacity is expected to reach

28 - 33 billion kWh and double after each 5 year period (about 53 billion kWh in 2005 and 80

billion kWh in 2010).

At the great demand of the economy, the power sector needs to develop all kinds of power

generation such as hydropower, coal-fired power, oil-fired power, new and renewable forms of

energy and more important is gas-fired power plants. At present, the main electric energy

resource is hydropower (sharing 63% of installed capacity) due to the distribution of natural

resource in different regions. The main fuel source for thermal power is coal in the North with

the coalfield in Quangninh province. Therefore, development of coal-fired power plants in other

regions is limited. Oil-fired power and small hydropower are major in the Central and the South

of the economy. However, hydropower construction needs long-time and large investment. This

power source structure has many disadvantages; for example, hydropower is only operated in

maximum capacity in rainy season, so shortage of power becomes a serious problem in dry

season. However, hydro- power tariff is the lowest, which is suitable for present situation of

power consumption.

At present, projects on hydropower of Yaly, Ham Thuan-Da My, Son La are being built

actively, Pha Lai coal-fired plant is being expanded with capacity of 600MW. VINACOAL has

projected a new coal-fired power plant with capacity of 300 MW in Cam Pha, another with

capacity of 100 MW in Na Duong and Cao Ngan of 100MW. While gas-fired power plants are

considered especially important as to their period of construction.

Existing power plants in Vietnam are shown in Table 5.

II. 2. The role of coal

In the 1990s, the "open door" policy of the Vietnam government was commenced. The Vietnam

economy has been stabilized step by step and has got significant advances. So there is an

increasing demand on coal for domestic use and export. The power generation sector and

cement industry is the major coal consumers in the economy. The growth rate of power

generation, cement and fertilizer was 26.0%, 10.0% and 7.0% in 1999, respectively. Besides the

coal demand for construction materials and household reached 25.0%. The coal demand in

Vietnam is still very low considering the pupulation of 75 million; the average coal supply is 80

kg –100 kg per person per year. Since 1989 the coal export has been increasing: coal export

reached 3.6 million tons in 1997, it was the highest rate in long time of coal exploitation in

Vietnam.

In 1999 and 2000, coal export reached 3.2 million tons and Vietnam coal was exported to

Japan, Western Euroup, Thailand, Philippines, Singapore, Taiwan, China, South Africa,

Western Europe and Australia.

According to the Master plan of coal industry development, annual coal production was

expected to increase from 6 million tons in 1994 to 11 million tons in 2000. Coal forecast for

different national economic sectors is shown in Table 6.

Some coal-fired power plants, such as Uong Bi, Ninh Binh and Pha Lai plant are planned to be

rehabilitated and expanded. A new coal-fired plant will be built with capacity of 600MW in

Quang Ninh (2002-2006), Cao Ngan of 100 MW (2001), Na Duong (in Lang Son province) of

100MW (2001) and a power plant with capacity of 600 MW in Hai Phong city. The existing

and newly built coal-fired power generation plants are shown in Table 7.


• Cement sector

Cement production is planned about 13,5 million tons in 2000

Over 50 vertical kilns in many localities and the Chonfong cement joint-venture plant in Hai

Phong city, the Van Xa joint-venture plant in Thua Thien Hue province and the Cat Lai cement

station in the South turned out 3.3 million tons of cement every year.

To meet the growing demand, the Vietnam Cement Corporation has accelerated construction

work with the most recently completed project being the But Son cement plant with capacity of

1.4 million tons in the Red river delta in Ha Nam province. This plant was started in 1999.

Cement production will be increased rapidly from 13.5 million tons in 2000 and will reach 30

and 40 million tons in 2005 and 2010, respectively.

According to information from the cement industry, production of construction material as

brick will also be increased. The demand for coal by the cement and construction material

industry will be increased as follows: 3.70, 5.40, 7.85, 8.35 and 8.85 million tons in 2000, 2005,

2010, 2015 and 2020 respectively.

• Other sectors

Beside the major consumers as noted above, a coal demand by other consumers such as heavy

industry, light industry, household fuel and mountain areas are at small rate, annual growth is

not high. The coal demand is projected at level of about 1.6 - 1.8 million tons per year. As fuel

for the rural area, coal use will be increased when the use of the traditional biomass fuel reduces

by the national policy of forest closure.

II. 3. The role of natural gas

In Vietnam, according to the Master Plan of Power Development approved by Government and

to the thermal power projects which have been and are being built, the demand of gas turbine

power generation is 11,1 billion kWh, which shares out approximately 37% of the total power

generation demand with required gas volume of 3.0 - 3.5 billion m 3 in 2000 and will be 28.1

billion kwh, which shares out 32.2% of the total power generation demand with required gas

volume of approximately 7.0 - 8.0 billion m 3 in 2010. Gas-fired power projects which have

been determined in the Master Plan of Power Development for period of 2000 - 2005 are Phu

My 4 and Nhon Trach plants.

• Demand for fertilizer production

Vietnam is an agricultural economy so the demand for fertilizer is high, particularly nitrogenous

fertilizer. In 2000, nitrogenous fertilizer consumption was about 5 million tons, only 6% of

them were produced in the economy (from coal). Although there are many limitations in

nitrogenous fertilizer production industry from coal, but it can still maintain for a period

because Vietnam has many coal sources with low price. On the other hand, with great gas

potential, Vietnamese government has a plan for nitrogenous fertilizer production development

to take initiative of ensuring supply of fertilizer for agriculture. At the end of 2000, two gasfired

nitrogenous fertilizer plants in the South and the Central will be built with capacity of

800,000 tons per year each. These two plants will need about 0.6 billion-m3 gas per year. After

2005, expected capacity of these two plants will be doubled, making total gas demand in 2005

be 1.2 billion m 3 and 2.4 billion m 3 gas in 2020.


Gas demand for steel production

A steel production plant with capacity of 1 million tons per year will be built in Thach Khe area

of the North Vietnam and will be operated at the end of 2001 with demand of 0.5 billion-m3

gas. The gas demand of this steel plant will be 1.0 billion m 3 per year.

• Gas demand for industrial zones, household and services

Industrial areas have great gas demand and gas will be supplied through gas pipeline system

form South Conson basin directly to Ba Ria-Vung Tau area, Dong Nai area, Ho Chi Minh City.

In the future, big gas reserve in Thai Binh province can supply gas to Ha Noi, Hai Phong and

Nam Dinh. With the above orientation, experts have estimated that the gas demand for

centralized industrial zones and household uses are 1.42 billion m 3 in 2000, 3.73 billion m 3 in

2005 and 4.86 billion m 3 in 2010.

In 2000, Petro Vietnam exploited over 9.25 million tons of crude oil; 8.59 million m 3 associated

gas and produced 137.000 tons LPG.

Gas demand supply for gas-fired power generation plants in 2010 and gas demand forecast for

other industrial sectors are shown in the Table No. 8 and No. 9.

The energy demand forecast of Vietnam by basic scenario is 26 billion kWh, 70.5 billion kWh

and 167 billion kWh in 2000, 2010 and 2020, respectively.

Coal demands are 7.4 million tons, 10.4 million tons and 17 million tons in 2000, 2010 and

2020, respectively. In there, coal demand for power generation is 5 million tons, 8.8 million

tons and 13.4 million tons in 2000, 2010 and 2020, respectively. Coal demand in 2020 is 17

million tons in case of nuclear power. If no nuclear power, the coal demand in 2020 will be

reached 30 million tons. While coal demand for power generation will be 18 million tons,

natural gas for power generation is 17 billion m 3 (for the power production of 85 billion kWh).

In that case, Vietnam wills not need to build nuclear power, to import coal and power

generation.

III. Conclusion

Coal and natural gas play an important role in Vietnam energy balance. In coming years, there

are many challenges for Vietnam coal and natural gas sectors to develop these two natural

resources to meet the demand of energy supply for economy economic sectors. The energy

resources is economic property which has capacity to distribute an important part for rapid and

long economic growth in two coming decades 2000-2020. Therefore, Vietnam government has

been developing appropriate energy policies in this field in order to enhance economic benefit

from coal and natural gas and to ensure National Energy Demand with lowest cost as well as

friendly environment.


tons)

Table 1. Reserve of anthracite in Quangninh area (million

Kind of

reserve

Total

reserve

Reserve of

open-pit

Reserve of

adit mine

Reserve of

shaft mine

Calculated 2,700.0 208.0 437.0 2,070.0

reserve proven

Probable

reserve

800.0 7.0 33.0 765.0

Total 3,500.0 215.0 470.0 2,835.0

Possible

reserve

6,500.0 - - 6,500.0

Reserve of 1,400.0 192.0 106.0 1,080.0

active mines

Source: Geology and Mineral Department.

Table 2. Some coal characteristics of Quangninh area

Parameter

Bao §ai

area

Mao Khe

area

Hon Gai

area

Cam Pha

area

Ke Bao

area

Volatile content 2-7 3.5-6.7 6.1-8.3 7.5-17.3 8.5-11.5

(%)

Ash content (%) 8-17 10-32 1.8-21 10-14 6-11

Sulfur content

(%)

Calorific

value(kcal/kg)

Gas content

CH 4 (m3/T)

0.3-1.0 0.5-0.7 0.2-1.0 0.3-1.0 0.3-0.5

8.000

7,000

Source: Institute of Mining Science and Technology

8,000

8.500

7,000-

6,000-

7,000-

8,300-

8,000-

8,500

0-5 5-10 20-25 20-30 20-30


Table 3. Coal supply for domestic consumption in the period

of 1995 - 2000 (1000 tons)

1995 1996 1997 1998 1999 2000

For domestic 4,809 6,075 7,100 7,805 6,719 8,328

Power 1,268 1,583 2,130 2,277 1,896 2,400

generation

Cement sector465 609 640 559 628 3,700

Fertilizer 195 424 360 201 178 480

Paper 156 135 170 172 170 480

Others 2,723 3,323 3,300 4,596 3,847 1,268

For export 2,836 3,638 3,600 2,901 3,235 3,074

Total 7,645 9,713 10,700 10,706 9,954 11,402

Source: Annual report of VINACOAL, 1999.2000. of VIETNAM COAL REVIEWS 2001

In the 2001 (8 Months of this year) Coal supply: 8,076 (1000 tons)

- For Domestic: 5,316 (1000 tons)

- For Export : 2,760 (1000 tons)

Table 4. Proved reserve and gas potential (billion m 3 )

No. Basin name

Proved

reserve

Potential

reserve

Total

1 Hong river 110 - 249 142 - 415 252 - 664

basin

2 Cuu Long basin 32 - 72 27 - 93 59 - 165

3 South Con Son 118 - 252 220 - 700 338 - 952

basin

4 Malay-ThoChu 18 - 37 27 - 105 45 - 142

basin

5 Other basins - 310 - 1,000 310 - 1,000


Table 5. Existing power generation plants in Vietnam

No. Plant name

Designed

capacity (Mw)

Available

capacity (Mw)

Hydro power 2,824 2,836

1 Hoa Binh plant 1,920 1,920

2 Thac Ba plant 108 120

3 Da Nhim plant 160 160

4 Tri An plant 400 400

5 Thac Mo plant 150 150

6 Vinh Son plant 66 66

7 Small hydro power 20 20

Coal-fired thermal

power

645 400

8 Pha Lai plant 440 300

9 Uong Bi plant 105 50

10 Ninh Binh plant 100 50

Oil thermal power

FO, DO

656 348

11 Thu Duc plant 165 156

12 Tra Noc plant 33 32

13 Gas turbine Can Tho 24 10

14 Diesel Mien Nam 204 65

15 Diesel Mien Trung 230 85

Gas -fired power 281 281

plant

16 Ba Ria 264 264

17 Turbine Thai Binh 17 17

Total 4,484 3,877


Table 6. Forecast on coal demand in national economy (million tons)

TT Items 2001 2005 2010 2015 2020

For domestic

1 Power 2.40 4.23 4.68 4.68 4.68

generation

2 Cement 3.70 5.44 7.85 8.35 8.85

3 Other 1.34 1.53 1.66 1.84 2.03

industries

4 Household 1.00 1.20 1.50 1.50 1.50

For export 3.20 2.20 2.20 2.20 2.20

Total 11.60 14.57 17.69 18.37 19.06

Source: The Master Plan of The Development up to 2010 and forecast to 2020

Table 7. Existing and new coal-fired power plants

Constructi

Capacity Total

No. Plant name on

(MW) (MW)

time

Situation

1 Uong Bi I 1971 55 x 2 110 existing

2 Ninh Binh I 1975 25 x 4 100 existing

3 Pha Lai I 1983 110 x 4 440 existing

4 Pha Lai II 1998 300 x 2 600 new

5 Na Duong 2002 100 x 1 100 new

6 Cao Ngan 2001 100 x 1 100 new

7 Quang Ninh I 2002 300 x 1 300 new

8 Quang Ninh 2006 300 x 1 300 new

II

9 Hai Phong option 300 x 2 600 new

10 Ninh Binh II option 100 x 1 100 new

Total 2,750


Table 8. Projects on gas-fired power plants and its gas demand

to 2010 (billion m 3 )

No. Plant name

Capacit

Completi

y 1998 1999 2000 2005 2010

on

MW

1 Ba Ria 327 1999 0.41 0.46 0.46 0.46 0.46

2 Phu My I 900 1999 - 0.85 0.85 0.85 0.85

3 Phu My II-1 431 1997 0.44 0.44 0.44 0.44 0.44

4 Phu My II-2 431 2001 - - - 0.44 0.44

5 Phu My III 620 1999 - - 0.59 0.59 0.59

6 Phu My IV 600 2002 - - - 0.57 0.57

7 Nhon Trach 1,200 2005 - - - 0.50 1.20

8 Thu §uc 165 - 2001 - - - 0.30 0.30

200

9 Independent 500 1998 - - - - 0.40 0.60

power plants 2005

10 Thai Binh 600 2000 - - 0.40 0.60 0.60

11 Other power 3,000 2006 - - 2.40

plants 2010

Total 8,974 0.85 1.75 2.74 5.15 8.55

Table 9. Gas forecast for other industry sectors (billion m 3 )

No. Industrial sectors 1995 1999 2000 2003 2005 2010

1 Fertilizer - 0.40 0.60 1.00 1.20 1.60

2 Oil chemical - 0.40 0.60 - 1.60 2.10

3 Steel - - - 0.60 0.60 0.60

4 Industrial zone 0.40 - 0,70 1.30 2.60

5 Service - - 0.05 0.50 0.30

6 Transportation 0.05 0.10 0.20

7 Household (Ton) 0.20 0.45 0.90

8 LPG 0.30 0.60 0.70 0.90 1.20

Total 0,4 1,10 3,70 2,30 6,65 9,50

The end


MOVE FROM GAS TO COAL:

ENERGY SECURITY ISSUES

Ms Yap Siew Hong

Director of Energy Section

Economic Planning Unit (EPU)

Malaysia


FROM GAS TO COAL : ENERGY SECURITY ISSUES

CHALLENGES FOR MALAYSIA

Yap Siew Hong

Director, Energy Section

Economic Planning Unit

I. INTRODUCTION

From gas to coal Are we taking a step backwards, when the logical trend

for environmental consideration is the need to move away from coal to gas which

is a more environment friendly fuel. Despite currently being a net exporter of oil

and gas, the realization that oil is no longer to be taken for granted as cheap and

plentiful energy resource, particularly after the 1980s oil shocks, resulted in

Malaysia pursuing energy policy objectives based on the availability of

indigenous energy resources, its relative costs and effect on the environment. In

line with this thrust, long-term objectives are aimed at reducing dependence on oil

as a single energy source, ensuring adequate and reliable energy supply, as well as

achieving higher utilization efficiency.

II. MALAYSIA’S ENERGY POLICY

Malaysia’s National Energy Policy (1979) aims to have an efficient,

secure and environmentally sustainable supply of energy in the future as well as

to have an efficient and clean utilization of energy. The three primary objectives

of the economy’s energy policy relate to the supply, utilization and environmental

factors.

Supply Objective

To ensure the provision of adequate, secure and cost-effective energy

supply by developing indigenous energy resources (both non-renewable

and renewable), using least-cost options and to diversify supply sources

(both from within and outside the economy).

Utilization Objective

To promote the efficient utilization of energy and discourage wasteful and

non-productive patterns of energy consumption.


Environmental Objective

To ensure that factors pertaining to environmental protection are not

neglected in the pursuit of the supply and utilization objectives.

Environmental challenges facing the energy sector cover climactic change,

air and water pollution as well as solid waste, which are mainly caused by

the increasing use of fossil fuels.

In achieving the above objectives, other energy-related policies, such as

the National Depletion Policy (1980) and Four-Fuel Diversification Policy (1981),

were formulated. The National Depletion Policy is intended to conserve the

economy’s energy resources, particularly oil and gas. In this respect, production

of crude oil is limited to about 600,000 barrels per day, whilst that of natural gas

to 2,000 million standard cubic feet per day (mmscfd). Meanwhile, the Four-Fuel

Diversification Policy was designed to reduce the economy’s over-dependence on

oil as a source of energy. The policy focuses on four main sources of fuel, namely

oil, hydro, gas and coal, aimed at ensuring their reliability and security of supply,

whilst reducing the dependence on oil in energy consumption. To further enhance

efforts in ensuring sustainable development of energy resources, utilization of

renewable energy (RE) as the fifth fuel will be promoted to supplement the supply

from the conventional energy sources.

III. ENERGY SCENARIO IN MALAYSIA

During the past two decades, demand for commercial energy grew rapidly

and exceeded the growth of the economy. Demand increased at an average rate of

7.5 percent in the 1980s and 7.7 percent in the 1990s, compared with a GDP

growth of 5.9 percent and 7 percent over the corresponding period.

When viewed from the source perspective, demand for energy increased

from 267.3 petajoules in 1980 to 1,167.1 petajoules in 2000, as shown in Table 1.

The main demand was for petroleum products (68.9 percent of total energy

demand in 2000), followed by electricity (17.6 percent), natural gas (10.3 percent)

and coal and coke (3.2 per cent). Although petroleum products remains to be the

leading source of energy, the demand for petroleum products had declined from

86.9 per cent in 1980 to 68.8 percent in 2000, reflecting the efforts taken to

restructure the energy consumption pattern. Meanwhile, final consumption of

natural gas grew from 0.6 percent to 10.3 percent over the same period.

2


Table 1

Final Commercial Energy Demand by Source, 1980-2005 (petajoules)

Source 1980 1990 1998 2000 2005

Petroleum products

232.4

(86.9%)

414.0

(74.8%)

714.1

(69.2%)

804.3

(68.9%)

1,139.1

(67.0%)

Electricity

31.2

(11.7%)

71.8

(13.0%)

184.7

(17.9%)

205.0

(17.6%)

320.0

(18.8%)

Natural gas

1.5

(0.6%)

45.7

(8.3%)

100.0

(9.7%)

120.0

(10.3%)

184.8

(10.9%)

Coal & coke

2.2

(0.8%)

21.5

(3.9%)

33.2

(3.2%)

37.8

(3.2%)

55.9

(3.3%)

Total

267.3

(100%)

553.0

(100%)

1,032.0

(100%)

Source: Eight Malaysia Plan (2001-2005)

Mid-term Review of the Seventh Malaysia Plan (1996-2000)

National Energy Balance, Malaysia (1980-1997)

1,167.1

(100%)

1,699.8

(100%)

In terms of supply, the total supply of energy increased from 391.8

petajoules in 1980 to 1,674 petajoules in 2000, as shown in Table 2. The main

sources of energy supply were crude oil 1 and petroleum products (53.1 percent of

total energy supply in 2000), followed by natural gas 2 (37.1 percent), coal and

coke (5.5 percent) and hydro (4.4 percent). There was a significant decline in the

share of crude oil and petroleum products from 87.6 percent in 1980 to 53.1

percent in 2000, indicating successful efforts to reduce the overall dependence on

a single source of energy and develop alternative sources of supply. In this regard,

the development of the domestic gas industry has increased the supply of natural

gas from 7.5 per cent to 37.1 percent over the same period.

1 Crude oil reserves are estimated at 3.39 billion barrels to last for 15 years

2 Natural gas reserves are estimated at 82.5 trillion standard cubic feet to last for 32 years

3


Table 2

Primary Commercial Energy Supply by Source, 1980-2005 (petajoule)

Source 1980 1990 1998 2000 2005

Crude oil &

petroleum products

344.4

(87.9%)

520.2

(71.4%)

804.8

(55.6%)

888.4

(53.1%)

1,205.2

(50.8%)

Natural gas

29.2

(7.5%)

114.4

(15.7%)

504.5

(34.8%)

622.2

(37.1%)

948.4

(39.9%)

Hydro

16.0

(4.1%)

38.2

(5.3%)

59.1

(4.1%)

73.0

(4.4%)

81.6

(3.4%)

Coal & coke

2.2

(0.5%)

55.5

(7.6%)

79.9

(5.5%)

90.4

(5.4%)

139.6

(5.9%)

Total

391.8

(100%)

728.4

(100%)

1,448.3

(100%)

Source: Eight Malaysia Plan (2001-2005)

Mid-term Review of the Seventh Malaysia Plan (1996-2000)

National Energy Balance, Malaysia (1980-1997)

1,674.0

(100%)

2,374.8

(100%)

The fuel mix for power generation is also based on the four-fuel

diversification policy but there are no pre-determined targets for the share of each

fuel type (oil, natural gas, coal and hydro). The implementation of the

diversification policy resulted in a major reduction in the dependency from oil in

the 1970s to increased usage of gas in the 1990s. In 1990, oil which made up 41.9

percent of the fuel mix is reduced to 5.3 percent in 2000 while utilization of gas

increased from 26.2 percent to 78.7 percent, as shown in Table 3. Currently, the

utilization of oil is by standby plants in Peninsular Malaysia and isolated oilfuelled

generation sets in Sabah and Sarawak. The successful diversification and

switch from oil to gas in the power sector came about due to the development of

the gas infrastructure the Peninsular Gas Utilization Project in Peninsular

Malaysia, the greater preference for more efficient technologies particularly by

the independent power producers (IPPs) and the need to consider and utilize

domestic resources.

4


Table 3

Fuel Mix in Electricity Generation, 1990-2005

(%)

Year Oil Coal Gas Hydro Others

Total

(gigawatthour)

1990 41.9 13.8 26.2 17.8 0.3 22,768

1995 11.0 9.7 67.8 11.3 0.2 41,813

2000 5.3 7.9 78.7 8.0 0.1 69,371

2005 3.0 30.3 61.0 5.4 0.3 102,340

Source: Eight Malaysia Plan (2001-2005)

Seventh Malaysia Plan (1996-2000)

The above trends on the energy consumption and supply patterns as well

as the fuel mix for electricity generation demonstrate the success of the current

energy policies pursued, namely the National Depletion Policy and Four-Fuel

Diversification Policy. Although the demand for natural gas is on the increasing

trend, the economy’s overall energy mix will be continuously reviewed so as to

ensure the long-term reliability and security of energy supply.

III.

CHALLENGES IN FUTURE COAL UTILIZATION IN THE

MALAYSIAN POWER SECTOR

The use of coal in electricity generation was initiated with the

commissioning of Tenaga Nasional Berhad (TNB) first coal-fired plant of two

units of 300MW at Kapar, Port Klang in 1988. Partly due to environmental

reasons, it took about 10 years before another two coal-fired units of 300MW

were commissioned at Kapar. In Sarawak, the 100MW coal-fired plant in

Sejingkat was commissioned in 1998. The economy’s coal-fired plant capacity

will be expanded with the commissioning of the 2,100MW TNB Janamanjung

plant in Perak and another two IPP-operated plants of 2100MW and 1400MW.

The trend towards coal provides a practical approach in optimizing the fuel mix

and reduce the over-dependence on a single fuel.

However, the energy sector is generally undergoing tremendous changes

in terms of technology, investments and regulatory framework. These changes

will require constant review of policies and adaptation of new strategies. There is

also the need to intensify current efforts in productivity and efficiency

improvements as well as provide a catalyst for fast take-off of renewable energy

projects in order to ensure a more sustainable development of the energy sector. If

5


these could be implemented successfully, it will definitely contribute towards the

enhancement of the competitiveness of the economy. The main challenge then is

to ensure adequate, secure and cost-effective supply of energy.

a. Promoting Investments in Coal-fired Plants

Initial capital outlay of a coal power plant is relatively higher than a gas

combine cycle power plant, it requires longer construction time and additional

infrastructure as well as logistically constraining choice of site. The challenge is

to provide an attractive climate for investments in coal power plants. In this

regard, the experience in developing the TNB Janamanjung coal plant will be

used as a benchmark for future competitive Power Purchase Agreements (PPAs)

with new investors in coal-fired plants.

b. Technology

Modern technologies will be critical in remedying environmental damage

that is generated from coal supply and combustion as well as improving the

economics of coal-based generation. This urgent need to reduce environmental

degradation, the clean coal technology – has become a mandatory requirement in

Malaysia. It is necessary to facilitate sustainability of coal in the generation mix,

and its investments cost. Our only concern being, this technology is still relatively

expensive and the cost of pollution control eventually are channeled to the

consumer through the selling price of the electricity to the utility. The difficulty

and challenge is to ensuring the balancing of returns to the project and the need to

have minimal impact on the selling price of electricity to the consumers. The

balancing act between making investments work and the need to provide

electricity at an affordable price remains a challenge.

c. energy – environment integration

Energy and environmental planning must be fully integrated. Energy

planning has increasingly becomingly complex and has extended beyond supply

issues but also behavorial changes and social costs. Economics and fiscal

measures are becoming important features for policy implementation while

technical efficiency and productivity improvements become critical factors for

consideration. The fundamental challenge is the delicate need to maintain the

economics as well as the environmental objective of the economy. As all of us

are aware, coal by its nature could easily contribute to the worsening of the

environment if mitigating factors such as emission control, stringent

environmental measures, and the adoption of clean coal technology are neglected.

All these factors overwhelmingly increases the costs of electricity production

which nullifies the effort of the Government to provide a basic need at a

6


easonable and affordable price to the general consumers. This difficult need to

balance the economic and social objectives will require major fine tuning of

approaches of project evaluation, implementation and planning while transition

arrangements for market-based options must constantly be developed in line with

the readiness of the economy and the consumers. These are challenging indeed,

not only for the planners, the regulators, the financiers but also to the investors.

d. indigenous coal supply

Although Malaysia import more than 90 per cent of its coal consumption,

Malaysia does have a good reserve of bituminous, anthracite and semi-antracite

with low to medium volatiles, low ash, very low sulphur and high gross calorific

value from 7,000 – 8,000kcal/kg. A total estimated 1,031.4 million tones reserves

have been estimated where 175 million tones are proven,113 million indicated

and 686 million tones inferred reserves. The largest coal deposits are located in

the Merit-Pila are in central Sarawak and the Meliau basin in the south-central

Sabah. Another 22 coal seams with thickness of 0.3 to 1.8meter have also been

identified in the Tutuh coal field. The latter deposits were discovered in surveys

conducted in the year 2000. These are reserves, at this point uneconomic to mine,

however, should there be any external supply or foreign exchange constaints, this

indigenous supply of fuel can be utilized to ensure reasonably secure supply of

resources.

VI.

CONCLUSION

Coal has been introduced into the Malaysian energy mix for more than a

decade. There were lessons learnt and there were positive results in technological

absorption and frontier enhancement. New growth areas relating to the provision

and support infrastructure and services for coal have been established and

developed. The mandatory clean coal technology is expected to reduce the

negative environmental impact of power generation. Combining market-driven

mechanisms and instruments, energy efficiency efforts, conservation investments,

continued fuel supply diversification and the expansion of indigenous energy

production, technology and capabilities are the challenges in ensuring the

sustainability of coal utilization. All in all, coal if properly balanced into the

energy mix will provide the strategy to balance between adequate, secure energy

supplies, economic growth and protection of the environment.

March 2002

7


FROM GAS TO COAL :

ENERGY SECURITY ISSUES

CHALLENGES FOR MALAYSIA

Yap Siew Hong

Director, Energy Section

Economic Planning Unit


Malaysia National Energy Policy

(1979)

3 objectives relate to:

qSupply

qUtilization

qEnvironment


Other Energy-related Policies

qNational Depletion Policy (1980)

qFour-Fuel Fuel Diversification Policy

(1981)


Energy Scenario in Malaysia


Demand for Commercial Energy

- petajoule

Source 1980 1990 1998 2000 2005

Petroleum products

232.4

(86.9%)

414.0

(74.8%)

714.1

(69.2%)

804.3

(68.9%)

1,139.1

(67.0%)

Electricity 31.2

(11.7%)

71.8

(13.0%)

184.7

(17.9%)

205.0

(17.6%)

320.0

(18.8%)

Natural gas 1.5

(0.6%)

45.7

(8.3%)

100.0

(9.7%)

120.0

(10.3%)

184.8

(10.9%)

Coal & coke 2.2

(0.8%)

21.5

(3.9%)

33.2

(3.2%)

37.8

(3.2%)

55.9

(3.3%)

Total 267.3

(100%)

553.0

(100%)

1,032.0

(100%)

1,167.1

(100%)

1,699.8

(100%)


Energy Supply by Source

– petajoule

Source 1980 1990 1998 2000 2005

Crude oil &

petroleum products

344.4

(87.9%)

520.2

(71.4%)

804.8

(55.6%)

888.4

(53.1%)

1,205.2

(50.8%)

Natural gas

29.2

(7.5%)

114.4

(15.7%)

504.5

(34.8%)

622.2

(37.1%)

948.4

(39.9%)

Hydro

16.0

(4.1%)

38.2

(5.3%)

59.1

(4.1%)

73.0

(4.4%)

81.6

(3.4%)

Coal & coke

2.2

(0.5%)

55.5

(7.6%)

79.9

(5.5%)

90.4

(5.4%)

139.6

(5.9%)

Total

391.8

(100%)

728.4

(100%)

1,448.3

(100%)

1,674.0

(100%)

2,374.8

(100%)


Fuel Mix in Electricity Generation

- %

Year Oil Coal Gas Hydro Others

Total

(gigawatthour)

1990 41.9 13.8 26.2 17.8 0.3 22,768

1995 11.0 9.7 67.8 11.3 0.2 41,813

2000 5.3 7.9 78.7 8.0 0.1 69,371

2005 3.0 30.3 61.0 5.4 0.3 102,340


Energy Mix Optimization

ä Energy Mix continuously reviewed to

ensure long term reliability and security of

supply

ä Optimize fuel diversification mix and

reduce over-dependence on a single fuel


Challenges in Future Coal

Utilization

ä Promoting Investments

ä Technology

ä Energy-environment environment Integration

ä Indigenous Coal Supply


SESSION 5:

Environmental Technologies

in Coal-fired Power Plant

Chair: Dr Boni Siahaan

Deputy Assistant for Mining and Energy Business

Ministry of State Owned Enterprises

Indonesia


POLLUTION

(SO X , NO X , PARTICLES)

TREATMENT

Mr Shigehito Takamoto

General Manager

Environmental Research Department

Kure Research Laboratory

Babcock-Hitachi K.K.

Japan


Pollution Treatment : SO2 and NOx Removal Technology at Babcock-Hitachi

ABSTRACT

Babcock-Hitachi's impressive record of designing and building thermal power plants

goes back more than 55 years ago. Babcock-Hitachi is also one of the foremost suppliers

of environmental control equipment and this system provides the best protection with

high reliability and economy. Babcock-Hitachi has built a solid base of R&D and design

experience recognized throughout the world.

We began developing Flue Gas Desulfurization(FGD) systems since 1972. Today, Wet

Limestone-Gypsum FGD systems are known as low-cost wet scrubbing systems, which

use an easily obtained absorbent(limestone) and produce a high quality, commercial

grade gypsum by-product. Our first commercial system(100MW plant) went into

operation in 1974, furthermore a 1000MW plant started up in 1990. Consequently, our

technology is now applicable to any kind of flue gas and covers a wide range of boiler

capacities.

We began developing NOx removal systems from flue gas in 1963. Today Babcock-

Hitachi is Japan's leading manufacturer of NOx removal systems, and many such systems

have been delivered to North America, Europe and Asia where they are helping to control

air pollution. This NOx removal system is called a Selective Catalytic Reduction(SCR)

process, feeded NH3 decomposes NOx into harmless N2 and H2O on catalyst. This simple

process both effectively removes NOx and is free from any by-products. It is thus easier

to maitain and provides stabler continuous operation.


BHK1


BHK2

BHK3


BHK4

BHK5


BHK6

BHK7

BHK8


BHK9


BHK10


BHK11


BHK12

BHK13


BHK14

BHK15


BHK16

BHK17


BHK18

BHK19


BHK20

CONCLUSION

Babcock-Hitachi's total flue gas treatment systems provide the best

protection for environmental control with high reliability and economy.

These environmental control systems easily meet the flue gas conrol

requirements of almostt any kinds of oil-,gas-,or coal-fired power plant.

(1) FGD SYSTEM

Total Engineering Capability with Boiler Plant Engineering

corresponding to various kinds of coal

Total Flue Gas Treatment Technology combined with ESP

Excellent Advanced Spray Tower Absorber Design

(2) DENOx SYSTEM

High activity and long life because of high erosion resistance for dust

Low possibility of dust plugging and low pressure loss

Wide application and experiences owing to stable supply by

own factory

BHK21


TRENDS IN COAL

COMBUSTION PRODUCTS

(CCP) UTILIZATION IN NORTH

AMERICA

Mr James MacLean

President

Dominion Ash

Canada


Trends in Coal Combustion Products (CCP)

Use in North America

presented by: James H. MacLean Peng

President, Dominion Ash

Member of Canadian Industries Recycling Coal Ash (CIRCA)

Canada

ABSTRACT

Coal Combustion industries in North America will have to reduce emissions of Mercury

and CO 2 in the next 10 to 15 years in response to public, government, and international

concern over climate change. The effects of previous emission reduction technology for

NO X and SO X , have resulted in increased levels of unburnt carbon and ammonia in the fly

ash, presenting problems for use in concrete. The history of CCP use since 1999, (Table

1) has been poor availability of quality fly ash (


Introduction: CCP Production and Use (Supply versus Demand)

The objective of the CCP industry in North America is to increase the utilization and

therefore avoid of landfill. The annual production of all CCP is 7.2 M tonnes 1 in Canada

(Fig. 1), and 98.2 M tonnes 2 in the US (Fig. 3). The average percentage CCP use in 2000

for Canada is 22% 1 (Table 2) and the United States is 35% 1 . ACAA and CIRCA must

establish new goals to for use in 10 years. If 50 % were established, this would falls

behind the experience in Europe, where data indicates 87% 3 of all CCP is used (Fig. 2).

The peak CCP utilization occurred in 1999. The impact of Low Nox Burner installation

on ash quality with the doubling of unburnt carbon in fly ash, removed many ash sources

from the market. High carbon ash cannot be used to replace Portland cement, as the

chemicals used for entrainment are absorbed.

CCPs are a group of products including Fly ash, Bottom Ash, and Synthetic Gypsum. Fly

Ash is the very light and fine material remaining after pulverized coal is burned. Perfectly

round glass spheres physically describes fly ash and are key to its value. Composition

comprises oxides of Aluminium, Iron, and Silica. Collection is from the boiler exhaust

gases as they pass through electrostatic precipitators, and fall into hoppers.

Bottom Ash is sized similar to sand, and falls by gravity to the boiler bottom and

collected either in dry or wet bottoms. This material is used as raw feed for Portland

cement production. Chemically these two materials are similar. CCP comprises by

volume an average of 10% of the coal fuel although this varies depending on the source

of coal. There are various uses for CCP, such as fly ash replacement for Portland cement

in concrete mixes, raw material in the manufacture of Portland cement, fillers for various

products, engineered compacted fills in highway construction, mine backfill, flowable

fills, etc.

The newest material considered a CCP, is synthetic gypsum. Since 1978 Forced oxidation

(FO) as applied to wet lime / limestone flue gas desulphurisation (FGD) technology, has

been employed in North America. Synthetic gypsum can replace naturally mined

gypsum. Since then 20 power plants have FGD operations constituting approximately

20,000 MW 4 of scrubbed generating capacity.

Synthetic gypsum has become a very important source of material for production of

Wallboard, and as a set retarder for cement mix designs. Some relevant approximate

parameters are removing 1 tonne of SO 2 requires 1 tonne of lime (CaO), produces 6

tonnes of gypsum sludge with 50% solids.

Trends: The US (short) story on how Environmental rules effect fly ash

The staged implementation of Emission Reduction Legislation lead to the introduction of

technologies starting with the retrofitting of older boilers, and new construction with Low

Nox burners, followed by Selective Catalytic Reactors (SCR), and FGD Scrubbers. The

potential for new emission reduction legislation in Mercury and CO 2 , will impact CCP

materials either by the technology of injecting activated carbon to scrub flue gas of

mercury, or fuel switching from Coal to Natural gas. The supply of fly ash with less than


4 % residual unburnt carbon for ready mixed concrete has fallen since 1999, due in part

to low Nox burner installation.

In the US, the Senate Environment and Public Works Committee, and the Bush

administration have drafted legislation. The EPA is expected to release a report in

January 2002, that will give power plants more leeway in meeting air pollution

standards. 5 The agency has been working on an overhaul of the Clean Air Act’s new

source review provisions, which require industrial facilities to install expensive pollution

control technology when they replace major plant modifications that increase emissions.

Industry complains that the rules are so strict it is hard to expand capacity and install

technology to boost energy efficiency. The new source review requirements are felt to be

so strict that they include routine maintenance.

In May of 2001, the Bush Administration directed the EPA to conduct an examination of

the impact of the program on investment in new capacity for industrial electrical or

refinery construction, energy efficiency and environmental protection.

“The integration of SCR as part of a multi pollutant control strategy is a necessity.” Says

Robert McIlvaine. “It is too costly to treat each pollutant separately”. The effect of SCR

on converting elemental mercury to a more soluble compound is one of the subjects

closely followed by this consultant.

In an article Clean Air Act Overhaul Schedule for Later This Month 5 , Sources familiar

with the report say the revised program will allow plant owners to set an emissions

threshold above which they would be required to install pollution control equipment.

Trends: The Canadian Story and Other Factors affecting Quality

In Canada, Environment Canada has proposed new air and solid waste regulations, which

could present barriers to increased CCP use. EPA determinations made in a 2001 review,

where CCP was considered a non-hazardous material, and said to have been

demonstrated suitable for soil amendment. The Canadian Transportation of Dangerous

Goods Regulation (TDGR) is to be revised and transferred from the Transportation

Ministry to the Environment department. Part of the review will determine how CCP will

be regulated, as a hazardous material or in a beneficial use category. Regulation overview

will as a result extend from production to end use.

Similar to work done by the ACAA in lobbying the EPA over its considerations, CIRCA

has been in contact with the Environment officials providing information clearly

characterizing what the CCP produced in Canada are in terms of metals contained and

potential for leachate. CIRCA is studying the leachate from material bonded in concrete

to also demonstrate the exact level of risk this poses.

A third area of government overview is a coalition of Eastern Governors, and Atlantic

Premiers, who meet each year to set bi-lateral environmental accords. In June of 2001,

the agreements reached include the reduction of Mercury and CO 2 , beyond levels

considered at the Federal level. The concern developed in this eastern part of North

America is due to prevailing eastern winds, location of industry concentrated to the west,

and the resultant pollution occurring over densely populated areas, in some cases

equal to the entire population of Canada.


While air emission regulations do effect the CCP produced, with higher carbon and

ammonia content, there is additional pressure from Solid Waste Regulations in both

economies, with increased restrictions for the landfill of CCP, and inter and intra state

and provincial movements. Areas of high population make landfill very expensive, and

recently one utility was recently forced to divert CCP from a local landfill to a 12 hour

round trip away.

Deregulation of the electric power industry, has influenced CCP, where the shift from a

central management in head offices, to the individual plants been considered profit

centres. Plant managers are now responsible for daily efforts to keep plant costs down

and face tipping fees up to $35 USD per tonne.

Trends: How the Mississippi figures into the CCP story

The geography of North America affects the production and regional market demands for

CCP. The dividing line is the Mississippi River that runs north to south, from the

Canadian border, through the United States to the Gulf of Mexico. The coals produced on

the east differ from those to the west, producing CCP with different amounts of Calcium

oxide (CaO). To the west, fly ash is high (20%) in CaO, while those to the east are less

than 10%.

Fortune provides the eastern market with this supply of low CaO to match Alkaline

aggregates. Alkaline aggregate reaction (AAR) is very much an everyday concern for the

Ready Mixed Concrete industry. Cement mix designs, especially for the High

Performance Concretes (HPC), demand fly ash, to prevent AAR reactions that lead to

cracking of structures.

Fly ash provides many benefits for the placing of concrete, including easier pumping,

flow into forms, prevention of segregation in the mix, and lower heat of hydration. The

finished product has many benefits with fly ash, such as increased compressive and

tensile strength, lower permeability, and prevention of the aforementioned AAR.

Public infrastructure in the east has original structures without fly ash, failing due to

AAR, and chloride penetration from road salt, causing reinforcing steel rebar to rust. The

result is a cracked structure and loss of strength. Canada budgeted $2.65 Billion in 2000

for infrastructure renewal.

New mix designs are without exception HPC mix designs with fly ash. The replacement

of failed structures, and new mega projects, such as the Boston Central Arterial job,

combined with the rapid decline in supply of quality fly ash, causes great concern for

designers.

Highway road construction traditionally uses asphalt as the road bed material. The

replacement of these surfaces every 3 to 5 years for every kilometre of highway,

compares poorly to those with concrete solutions twice the life. Increased dependence

upon heavy transport for goods and services leaves many sections failing within one year.

Asphalt roads have a higher rolling resistance for heavy traffic, resulting in a 10%

increase in fuel consumption, when compared to concrete construction. Less pollution,


and dependence on imports of oil would be the benefit. Vehicles produce 1/3 of all GHG

in North America.

Trends: Industry practices supporting increased CCP use

Homes in Canada and the US has seen increased Insulated concrete form (ICF),

construction replace the traditional wood frame construction. The Portland Cement

Association (PCA) reports, 40% less operating energy for ICF versus wood frame. PCA

estimates ICF will have 12% of the housing construction market in Canada by 2010.

GHGs reduction could result in 6.8 - 10.9 million tonnes per year.

A US Industry study 6 forecast for 2001 to 2010, indicate fly ash, will lead mineral

additives growth. “Fly Ash, long used elsewhere in the world as an additive to or partial

replacement for cement, is expected to continue its penetration of the US market, as

contractors avail themselves of the performance benefits of fly ash use coupled with its

low cost.” The competing supplementary cementitious material (SCM), blast furnace

slag, is “expected to register subpar growth, with value gains held down by flat pricing

outlooks.”

Mineral Spotlight reported in May 2000 7 , that strong demand from the construction

industry has seen record levels of gypsum production and consumption, and the

commencement of new wallboard facilities. The Gypsum association reported that

wallboard demand has risen 5% per year on average for over 10 years. In both the US and

Canada in 1999, a demand boom saw US Gypsum ration wallboard to customers and

issue a letter to customers explaining reasons for wallboard shortages.

In the US, seventeen (17) large wallboard plants, have been constructed or are under

construction since 1998, and the majority are designed to use only synthetic gypsum. This

is due to the significant cost advantage of synthetic gypsum over mined gypsum. The

current consumption of synthetic gypsum is only 10% of total demand, while Japan leads

the world with 65% of supply. Current production of synthetic gypsum is 6.3 M t/y (US),

and 0.6 M t/y. (Canada).

In 1999, US Gypsum consumption was about 31.8 M tonnes, about 72% 8 , which

according to Merrill Lynch was used to produce wallboard. A further 16% is used to

produce Portland cement, while other uses, including agriculture, smelting, glassmaking,

account for the remaining 12% 8 . The shortfall in domestic production is made up of

imports of crude gypsum. Canada provides 68% 8 of imports to the east, while Mexico

provides 23% to the west, and the remainder from Spain (8%) 8 .

Trends: Portland cement production and avoidance of CO 2

Approximately half of the world’s 60,000 M ft 2 wallboard capacity is located in the US,

according to United States Geographic Service (USGS) estimates. Demand from housing

markets saw North American wallboard plants operating at 98% of capacity in 1999, as

demand caught up with supply.

US production topped 29,000 M ft 2 a 7.7 % increase over 1998’s 27,000 M ft 2 , while

Canadian manufacturers shipped almost 30% of their production to the US, and saw a

10% increase in sales to 3.88 M ft 2 in 1999 9 .


Cement production (1999) in the US was 86 M tonnes, and 12.6 M tonnes in Canada.

Projections are 114 M tonnes and 18 M tonnes for each economy respectively by 2010.

The increase in production from 1990 to 2012 is estimated as over 59%.

Environmentalists are concerned over the impact of cement powder production of CO 2 ,

and its potential contribution to Green house gases (GHG).

Under Kyoto, the developed economies will have to reduce their GHG emissions to 5.2%

below 1990 levels in the first commitment period of 2008 to 2012. The reduction target

for the US is 7% below 1990, and Canada is 6%. If the emission reduction targets were

spread evenly over all economic sectors in the Annex I economies, the cement industries

in each would have to reduce their GHG emissions by the same amount as the applicable

national commitment. For example, the US cement industry would have to reduce its CO 2

emission in the first budget period 2008 to 2012 to 7 % below the 1990 level. The cement

industry in Canada has had a very strong average growth in production in the years 1990

to 1999. Should the growth continue Canada would be 75% above 1990 levels. 10

Current cement production technology does not allow for reductions in CO 2 with

increased production to match the reductions in emissions required to meet the targets.

Australia adopted strategies to reduce its CO 2 release per tonne of cement produced by

11% since 1990, while the total cement industry in the same period reduced its footprint

by 4%. There is room for increased efficiency in reducing the average fuel consumption

per tonne of clinker. Supplementary cementitious materials now replace about 20% of the

clinker in cement in this economy. The use of mineral additions in general purpose and

blended cements is expected to double over the next few years.

Trends: Where does fly ash fit in the Portland cement CO 2 reduction strategy

In Canada, average energy efficiency for Portland cement production is nearly optimized

with only one wet plant still in operation. The cement industry has committed itself to

reduce CO2 emissions per metric tonne of cement produced in 2000 by 4.5% from 1990

levels 10 . The estimated average clinker content in cement is 92% 10 . The industry has

committed to increased use of SCMs in blended cement, and to support increased

replacement of Portland cement in concrete. CO2 emissions per tonne of cement are

estimated at .85 tonnes.

In the US, average energy efficiency and estimated CO 2 emissions are higher than

Canada. The production from wet plants represents 22% of total US production in 1999. 10

Fly Ash is estimated as replacing 8% of cement in concrete, and 1% of total cement

consumption are due to blended cements in 1999. The American Portland Cement

Association (APCA) is in the process of setting an industry target for reducing CO 2

emissions. CO 2 emissions per tonne of cement are estimated at 1.0 tonnes. 10

The potential Portland cement replacement levels for the US and Canada could see,

choosing an arbitrary 20% replacement level, results in 17.2 and 2.6 M tonnes

replacement. This would result in a fly ash utilization of 60% and 43% of current

production respectively. The cement industry offset for CO 2 emission avoidance would

therefore be 22% and 20% respectively. The potential for replacement lies between how

much quality material can be economically transported, and the silo price for fly ash.


The stage is now set for the CCP industry to provide a quality material. A product versus

a by-product, a consistent supply, without effect from fluctuating plant unburnt carbon

levels is needed. The producers now have the economic incentive to avoid landfill, and

they need CO 2 credits, only available with the replacement of fly ash into concrete. The

cement industry needs to offset its forecasted increase in cement production with the

replacement with fly ash, or other SCMs. The CCP industry needs a consistent quality fly

ash in order to realize this potential. The technologies to beneficiate fly ash are available

today and next year new options are promising to be commercialized.

Trends: How to remove carbon and ammonia from a finely divided material

There are several carbon and ammonia removal technologies available either in

commercial or pilot stage operation. Some do both, while others do one, and not the

other. Costs to install vary, operational costs are worth comparing, and some provide no

waste stream, and others a ‘fuel alternative’.

Categorizing the methods or technologies for fly ash beneficiation is as follows:

1. Carbon burnout

2. Microwave carbon burnout

3. Electrostatic separation

4. Particle separation

5. Carbon fixation

6. Ammonia fixation

7. Carbon floatation

Carbon burnout (CBO) is commercialized with the Progress materials CBO plants in the

US. They have successfully operated and removed carbon and ammonia with heat

recovery. Dominion Ash in Canada has marketed a Microwave Carbon Burnout (MCB)

technology developed and pilot tested by EMR Microwave Technology Corporation over

the last two years. Commercialization is expected in Canada in late 2002.

Electrostatic separation is commercialized by STI in the US, and has successfully

produced quality ash, with a carbon rich waste stream. Ammonia fixation is possible as

an add on.

Particle separation has used been successful, but depends on having a consistent material

size and distribution to efficiently remove the relatively coarse carbon particles. Air

classification works very well if it finds the right fit. Ammonia removal is obviously a

needed add on.

Carbon fixation by ISG is promising, but is limited to material meeting current maximum

carbon. Carbon and ammonia fixation while possible, have not competed studies of longterm

effects on concrete.

Microwave Carbon Burnout (MCB)

This process evolved from EMR technology developed for the mining industry. Carbon

content is a problem in ores, such as gold, where as little as 0.5 % carbon robs the final

stages of 20% of the gold available. EMR was contracted to design and build a pilot plant


to demonstrate the effectiveness of microwaves to remove carbon. Carbon is a perfect

microwave energy receptor (See Diagram 1).

Near the end of this successful work, EMR engineers suggested coal fly ash for

development. The two materials are very similar in size distribution. Dominion was

contacted to help EMR develop the MCB technology for fly ash, which was successfully

done in 2000 (see Drawing 1).

Samples of fly ash from all over the world have been received and tested. Carbon

contents in the fly ash ranged 2 to 27 %, has been successfully processed to a consistent

product, with as little carbon present as deemed desirable. Ammonia has been received at

over 2000 PPM and levels were reduced to undetectable.

In 2001 EMR and Dominion continued important environmental testing to study the

disposition of metals during the MCB process, this has demonstrated all metals including

mercury, remain in the ash.

Emissions are very low in NO X , as there is no fuel source other than carbon. CO 2

emissions from the combustion at the Power Plant and from MCB operation total a very

small percentage of the CO 2 offset from Portland cement replacement. The carbon is a

perfect target for microwave energy, while the remaining material is invisible glass

particles.

Fly ash residency time is very short (less than 10 minutes), and so the throughput of

material is very fast. The MCB plant is very small (15 x 18 M 2 ), and economical to build

and more importantly very cheap to operate. Heat recovery is easily incorporated.

MCB designs are completed for 300, 000 tonne sizes, and use a modular design. This

allows increasing output 100% while the capital cost increases only 25%.

The first commercial plant is expected to break ground in Canada in 2002. It will be

capable of processing 300 tonnes per day, 7 days per week, 24 hours per day. Computer

control allows the operator to complete other work. Carbon levels can fluctuate over wide

ranges in a short period and the system adjusts automatically. The same can be said for

Ammonia removal.

Strategies for increasing the utilization of CCP

While efforts are directed to lobbying environmental agencies, the main focus of shortterm

strategy by the ACAA and CIRCA is to increasing the awareness for increased use

of CCP. For example reaching out to new graduates from Engineering programs,

communication efforts to reach sectors of the public, Industry designers and regulators,

and environmental lobbyists.

CIRCA has placed a purchase order to the University of New Brunswick, for an

Education Module that will be Web based, and is aimed at the senior Civil engineering

materials course. Continuing education will also be able to take advantage of this course.

The course module will be tested out this spring and made available to all universities for

the fall of 2002.


The key messages to be sent out are that fly ash is a valuable engineering material, not a

waste or by-product. It is a superior SCM in its benefits and value.

The logistics required for getting comparatively low value CCP materials to market is a

significant problem area. Storage, rail rates, and trucking fuel costs are all barriers to

avoiding landfill. Increasing the value of CCP before it leaves the production site, is one

obvious solution to overcoming these areas.

Much of the emphasis in this paper has been for the replacement of Portland cement by

fly ash. It is recognized by our industry that this traditional application will not provide

the solution to complete landfill avoidance. Value added products such a Light Weight

Aggregates , and Non-traditional applications will provide additional markets for the

balance of CCP.

ACAA and CIRCA strongly feel that any use of CCP must be effective, economical,

follow sound engineering, and be environmentally acceptable.

REFERENCES:

1. Canadian Industries Recycling Coal Ash (CIRCA) - Production and Use 2000

2. American Coal Ash Association (ACAA) - 2000 Production and Use

3. European Association for Use of the By-products of Coal-Fired Power Stations

(ECOBA) - Development of Production and Utilization of CCPs in Europe (EU15) from

1993 to 1999

4. Makansi, Jason. and William Ellison , Worldwide Progress In The Utilization Of

Byproduct Gypsum

5. Clean Air Act Overhaul Scheduled for Later This Month, Chemical Marketing

Reporter, January 7, 2002

6. Fly ash, silica fume to lead mineral additives, Cement & Concrete Additives, Study

#1465, September 2001

7. Gypsum, Industrial Minerals, Mineral Spotlight, May 2000

8. Wallboard Wonderland The North American gypsum market, Harris Paul Assistant

Editor, Industrial Minerals, January 2001

9. Gypsum Markets, Industrial Minerals, January 2001

10. Cahn David and Michael Nisbet, Reducing the Intensity of Greenhouse Gas

Emissions in Cement Manufacture: the U. S. Versus Annex 1 Economies


Trends In Coal Combustion Products

(CCP)

Use in North America

(Canada and United States)

APEC Conference

Kuala Lumpur

March 5, 2002


Who are we

• Voice of Canada’s coal

combustion industry - represent

CCP producers, and marketers

• Offices in Montreal, Toronto,

Halifax, Fredericton, Calgary,

Edmonton and Vancouver

• Work with strategic partners

to expand the use of CCP

solutions in Canada

• Provide our members with a

vehicle to participate in

public affairs


We Are Coast to Coast

Power Plant

Distribution

Center


Member Companies

CAN ASH CCP LTD

Fredericton, New Brunswick

LAFARGE CANADA INC.

Montreal, Quebec

ST. LAWRENCE CEMENT INC.

Mount Royal, Quebec

NB POWER CORPORATION

Fredericton, New Brunswick

TRANS ALTA CORPORATION

Duffield, Alberta

POZZOLANIC INTL LTD

Delta, British Colombia

NOVA SCOTIA POWER CORP

Halifax, Nova Scotia

INLAND CEMENT LIMITED

Edmonton, Alberta

ONTARIO POWER GENERATION

Toronto, Ontario

MANITOBA HYDRO

Winnipeg, Manitoba

EPCOR UTILITIES INC

Edmonton, Alberta


Continuous Innovation

R&D efforts improve quality of Canadian infrastructure

• CIRCA is a leader in codes & standards,

and use of CCP in HPC bridge design

and construction

• CIRCA works closely with the scientific

research community and strongly

supports universities in R& D efforts.

• Innovations such as RCC, HPC, new

concrete pavement designs, housing

and waste management solutions are

based on solid R&D


Coal Combustion Products (CCP)

• CCPs are a group of Products;

• Fly Ash, Bottom Ash, Slag

• Synthetic Gypsum

• Production of High and Low CaO CCP

• East Low CaO (< 10%)

• West High CaO (>20%)


Coal Combustion Products (CCP)

• Synthetic Gypsum is the newest CCP

• 1 tonne of SO 2

requires 1 tonne of

lime (CaO), produces 6 tonnes of

gypsum sludge with 50% solids.

• Synthetic Gypsum replaces Natural

Gypsum in Wall board, and as a set

retarder for cement mixes


Some Fly Ash Facts

• Fly Ash produces superior quality

concrete and is needed in all

concrete mixes. In fact, Fly Ash

is necessary to make High

Performance concretes.

• Cement and concrete go

together like yeast and bread.

Fly Ash adds to this recipe.

Although it comprises only

15 to 50 % of the total cementitious

content, Fly Ash contributes to

increased strength, impermeability,

and resistance to Alkaline Aggregate

Reactive materials.


A CCP Economic and

Environmental Contribution

• Use of Fly Ash in concrete

increases the expected life of a

structure by 100%. This saves

public monies by avoiding

unnecessary repair or

replacement of infrastructure

from coast to coast.

• Use of Fly Ash in replacing

Portland Cement offsets CO2

GHG production.


Canadian Utilization - 2000

Figure 2


US Production and Use - 2000

Figure 3


European (ECOBA) Utilization - 2000

Figure 4


Contributing to clean air and reducing CO 2

The Industry reduces CO 2

emissions and contributes to

cleaner air by the following actions:

• Promoting the use of coal combustion products (CCP) such as fly

ash to replace a portion of cement in concrete.

• Reduces the production of CO 2

with the replacement of Portland

Cement in the Ready Mixed Concrete.

• Allows the increased use of concrete in the construction of Public

roadways, reducing road friction and saving fuel by up to 10 %

and lowering emissions.


Public Policy Interests

We can provide solutions and expertise

Environmental Policy

• clean air

• climate change

• contaminated sites

• regulatory harmonization

Infrastructure Renewal

• rebuilding/expanding highways

• trade corridors

• sewage treatment

• water treatment

• housing


Environmental Solutions

Concrete highways contribute to clean air and reduce CO 2

• NRCan is investing $3.5 million over five years to

promote concrete highways as a means of reducing

GHG emissions

• Year-round average of up to 11% less fuel required for

trucks (NRC)

• Lower maintenance requirements reduce congestion

and idling traffic, resulting in cleaner air


Environmental Solutions

Building with concrete contributes to clean air and reduces CO 2

Insulating Concrete Form (ICF) Houses:

• use 40% less operating energy than traditional wood framed

homes

• 12% market share in 2010 would reduce GHG by 6.8 Mt - 10.9 Mt

House Construction and Operating Energy CO 2 (Natural Gas)

450

House Construction and Operating Energy CO

2 (Oil)

300

400

250

350

300

200

CO 2 (t) 150

100

250

CO 2 ( t )

200

150

100

50

50

0

wood

0 1 5 10 15 20

ICF

year

w o o d

0

I C F

0 1 5 10 15 20

year

Residential GHG 7% of Canadian total


Environmental Solutions

Building with concrete contributes to clean air and reduces CO 2

House Construction and Operating Energy CO 2 (Natural Gas)

300

250

200

CO 2 (t)

150

100

50

0

wood

0 1 5 10 15 20

ICF

year

Residential GHG 7% of Canadian total


Environmental Solutions

Building with concrete contributes to clean air and reduces CO 2

450

400

350

300

House Construction and Operating Energy CO

2 (Oil)

CO 2 ( t )

250

200

w o o d

150

100

50

0

I C F

0 1 5 10 15 20

year

Residential GHG 7% of Canadian total


Environmental Solutions

Contaminated site remediation, hazardous waste disposal, and

agricultural waste management

• Fly Ash in Cement-based

solidification and

stabilization (S/S) treatment

can treat industrial wastes

for disposal

AND restore contaminated

lands to productive use

• Fly Ash in Concrete manure

storage facilities improves

prevention of leaching

• Industry is working with

strategic partners to

develop an energy smart

solution to agricultural

waste management

Solidification:

• Refers to changes in the physical

properties of a waste. The desired

changes usually include increased

compressive strength, decreased

permeability, and encapsulation of

hazardous constituents.

Stabilization:

• Refers to chemical changes of the

hazardous constituents in a waste.

The desired changes include

converting constituents into a less

soluble, less toxic form.


Working with Government

CIRCA is committed to providing cleaner air for Canadians

• CIRCA advises Government on how to reduce air

pollutants:

1. Public Works has included the use of CCP in its

latest

Canada Wide Standard

2. Environment Canada is receiving input on the

characterization of CCP produced in Canada

and its use,

providing useful data for

understanding the environmental impact

when deciding positions in legislation and

international agreements.


Advocacy Issues

The CCP Industry would like the Government to:

• adopt a “credit-for-early-action” plan with respect

to CO 2 reductions

• recognize the industry’s support of using CCP by

offering CO 2 credits * Coal Combustion Products

• consider concrete, cement’s end product, when

measuring C0 2


Infrastructure Renewal

An investment in prosperity

• The CCP Industry applauds the Government on its $

2 Billion infrastructure program announced in

Budget 2000.

• The CCP Industry supports the call from the

provinces and various sectors of the economy for

more investment in infrastructure.

• The CCP Industry is ready to add value to the

government’s initiatives by providing expertise,

cost-effective and environmentally sustainable

solutions.


Concrete Highways

Provide good value for taxpayers’ dollars

• Last twice as long as asphalt,

therefore better value over life

of highway

• Require lower maintenance:

reduces delays to users

• Improved safety from better

visibility at night and superior

traction

• Contribute to economic

efficiency and productivity

through reduced fuel

consumption for heavy trucks

and no spring weight

restrictions


Concrete Highways

The ideal solution for trade corridors

Government should consider concrete as the paving material

of choice for trade corridors because:

• Concrete highways absorb the weight of freight trucks

without deforming and therefore last longer

• Heavy trucks require up to 11% less fuel when driving on

concrete, a savings for the economy and the environment

• Almost 1/3 of all GHG comes from truck and car emissions


Environmental Dividends

Manure Waste Treatment

• Growing public awareness and concern over

state of infrastructure that maintains water

supply

• Increased concern as farms get bigger and

livestock production increases - increased

manure waste

• Industry investing in R&D on concrete in waste

management solutions like biogas technology


Cementing Canada’s

Future

The CCP Industry has the expertise, the product and the capacity to help

build a superior infrastructure for generations to come.


Historical US Production and Utilization Profile

Table 1


Canadian Fly Ash Production and Use

Table 2


Canadian Production - 2000

Figure 1


Canadian Production - 2000

Figure 1


Canadian Utilization - 2000

Figure 2


Canadian Utilization - 2000

Figure 2


US Production and Use - 2000

Figure 3


US Production and Use - 2000

Figure 3


CLEAN COAL IN A

COMPETITIVE ELECTRICITY

MARKET

Mr Lindsay Juniper

Managing Director

Ultra-Systems Technology

Australia


CLEAN COAL IN A COMPETITIVE ELECTRICITY

MARKET

Lindsay Juniper

Director, Fuel & Power

Ultra-Systems Technology Pty Ltd, Brisbane, Australia

Coal in Sustainable Development in the 21 st Century

4 – 8 March 2002

Kuala Lumpur, Malaysia

ABSTRACT

New technologies for electricity supply that are under development to meet future demands

are being driven by two main factors:

• The de-regulation of the electricity industry from centralised State-owned monopolies to a

competitive market.

• Environmental issues in relation to atmospheric (and other) emissions from the

production of electricity.

On the one hand the technology must have low emissions (particulates, SO 2 , NO x and

greenhouse gases) and on the other they must provide competitive electricity in the free

market. These two objectives are mutually exclusive and only pressure by Governments is

forcing utilities to increase the price of electricity to pay for lower emissions.

Many see coal as the main contributor to the global environmental problems. However, it is

only now that these people are realising that it is not feasible to replace coal as the major

energy source of the world. So what do we do The energy industry has the answer, and it lies

in new technologies based on zero emissions.

This paper overviews the trends in the deregulated electricity market and discusses the issues

relating to the implementation of new electricity generation technologies in this market. It

also discussed the response from the coal industry that might be appropriate to turn black (or

brown) coal slightly green.


Clean Coal in a Competitive

Electricity Market

Lindsay Juniper

Ultra-Systems Technology

Brisbane, Australia


Overview

♦ Electricity Supply in Australia

− Trends, Renewables

♦ Incentives for Development of New

Technologies

− Costs, Environmental

♦ Power Plant Technologies

♦ Environmental Performance

− Efficiency, Pollutants, Greenhouse, Costs

♦ Green Coal & Greenhouse Gas

− Who are the Emitters

− Implications for the Coal Industry


Electricity Supply in Australia

Gas`

9.3%

Hydro

8.6%

Oil

0.4%

Renewables

0.7%

270

•44 GW Installed Capacity

•Up to 58 GW in 2010

250

Coal

81%

Energy Demand (TWh)

230

210

190

ESAA Prediction

3% Growth Rate

170

150

1996 1998 2000 2002 2004 2006 2008 2010 2012

Year


Interconnected System


NEM - The “spot” market

♦ Central Pool controls

dispatch

♦ Generators bid in halfhourly

intervals

♦ Wholesale market bid

for energy

♦ Generators paid halfhourly

spot price

♦ Wholesale customers

pay spot price less

Demand (MW)

7,000

6,000

5,000

4,000

3,000

2,000

1,000

Demand

Pool Price

350

300

250

200

150

100

50

Pool Price ($/MWh)

losses

0

0:00 4:00 8:00 12:00 16:00 20:00 0:00

Time of Day (hr)

0


Renewables

♦ Solar

♦ Wind

♦ Tidal & wave

♦ Hydro

♦ Geothermal

♦ Biofuels

♦ Wastes

♦ Co-firing

Source Capacity

(MW)

Energy

(GWh)

Hydro 7,500 20,000

Bagasse 340 1,200

Wind 32 70

Solar 1 4

Total 7,873 21,274


Incentives - Costs

♦ Capital

♦ O&M

♦ Fuel

− Change fuels

− Cheaper coal

Electricity Supply Cost (Aus$/MWh)

200

150

100

50

COAL - $0.80/GJ

GAS - $3.00/GJ

Gas Turbine - $3.00/GJ

3,000

Capital Cost ($/kW)

2,500

2,000

1,500

1,000

0

0 20 40 60 80 100 120

Annual Capacity Factor (%)

500

0

1985 1990 1995 2000

Year


Incentives - Environmental

♦ Greenhouse gases

− Type of fuel

− Cycle efficiency

− Renewables

♦ Others

− NOx

− SO 2

− Particulates Fuel CO 2 Emissions

Coal

(kg/MWh)

850 – 900 for sub-critical,

down to 800 for super-critical

Natural gas 500 – 600

Renewables: Zero (Not allowing for Whole

Solar of life emissions)

Renewables: >1,000 but considered CO 2

Biomass neutral


Power Plant Technologies

♦ Coal

− Super-critical PF

− IGCC

♦ Gas

− Advanced GT

− Fuel cells

♦ Renewables

− Solar: voltaic, thermal

− Wind

− Biomass

♦ Zero CO 2


Environmental Performance

Plant Details

Coal Gas Renewables

Solar PV Solar Thermal Wind Biomass

Unit Size 200 – 1,300 MW 200 – 750 MW 0.01 – 1 MW Up to 200 MW Up to 2.5 MW Up to 100 MW

Capacity factor 75 – 95% 75 – 95% 5 – 20% 5 – 20% Highly site

specific, but

typically

around 20 –

50%

50 – 80

depending on

availability of

fuel

Emissions

Particulates

SO 2

NO X

Low but needs

gas clean-up

Depends on coal

sulphur content

High

uncontrolled.

Moderate with

appropriate

clean-up

CO 2 (kg/MWh) 800 – 900 460 – 600 Zero – but has

significant

“whole of life “

emissions

Cost of

Compliance

Not significant Zero Zero Zero Low but needs

gas clean-up

Not significant Zero Zero Zero Depends on

fuel sulphur

content

Expensive Zero Zero Zero Very cheap

Zero+ Zero+ Very high –

taken as CO 2

neutral

High Moderate Low Low Low High


Cost of Compliance

Cost Item Coal-Fired Plant Gas-Fired CC

Air pollution control 6 – 18 % 0 – 6 %

Cooling 0 – 2 % 0 – 3 %

Waste disposal

Environmental charges 0 – 9 % 0 – 5 %

Total 10 – 26 % 0 – 9 %


Green Coal

Who are the emitters


Implications for the Coal Industry

♦ Bundled coal contracts

Clean coal

− Coal quality

− Blending

♦ Low GHG (clean) coal

West Elk

Plateau

Optimum

Kleinkopje

Duiker

Parambahan

KPC Pinang

Kaltim Prima

Adaro

Wallarah

Ulan

South Bulli

Dartbrook

Clarence

Camberwell

Bulga

Wilkie Creek

Jeebropilly

Ebenezer

Monto

South Blackwater

Newlands

Moura

Jellinbah East

Gordonstone

Ensham

Curragh

Cook

Collinsville

Blair Athol

Blackwater

918

936

942

943

800 850 900 950 1000 1050 1100

957

952

960

959

958

968

964

967

967

966

974

974

973

969

975

988

983

983

982

986

987

987

993

CO2 Emissions (kg/MWh S/O)

1001

1006

1009

1023

USA

Sth Africa

Indonesia

NSW

Walloon

Queensland


There is a Solution

♦ The world cannot do without coal in the

medium term

♦ This means that some rational debate may

eventuate

Clean coal technology has come a long way

− But not far enough

− Zero emissions is the answer

We recognise that the use of coal is not clean enough for our

children, but we have the answer, and we’re working on it!


SESSION 6:

Present Situation and Trend of

High Efficiency Coal

Combustion Technologies

Chair: Mr Hiroaki Ichinose

Deputy Director

Coal Industry Division, ANRE

Ministry of Economy, Trade and Industry (METI)

Japan


FEASIBILITY OF

NEW COAL FUELED

POWER PLANTS

Ms Natalie Rolph

Chief Economist

Black & Veatch – Energy Services ong>Groupong>

USA


Feasibility of New Coal Fueled Power Plants In the US

(presenter: Natalie Rolph, Chief Economist

Black & Veatch – Energy Services ong>Groupong>, USA)

ABSTRACT

This paper discusses how the differential between natural gas and coal prices, and the

difference in public versus private financing affects the financial feasibility of new coal

plants in the US. Recent advances in the design of new coal generators and coal plant

systems are described. Opportunities and implications of using cheaper, lower quality

coals are addressed, as are the impacts of plant size, ideal site conditions and more

stringent environmental regulations. Implications for US coal industry suppliers are

suggested.


Coal In Sustainable Development

in the 21st Century

Feasibility of New Coal

Fueled Power Plants

In the US

Natalie Rolph


Topics

■ New Interest in Coal Generation

■ Recent Design Enhancements / Current

Configurations and Costs

■ Private Developer Economics

■ Regulated and Public Power Economics

■ Factors That Alter Coal Economics

■ Implications for Coal Industry Suppliers

NR(4) - 2


New Interest in Coal Plant Development

Announced US Coal Projects

NR(4) - 3


Actual US Coal Plant Designs

>10 Years Old

6,000

5,000

5,315

4,305

MW of Most Recently

Installed Coal Capacity

by Design Year*

4,000

3,000

2,000

1,000

504

0

1984-1986 1987-1990 1991-1994

* Assumes Typical Design Lead Times 6 Years Prior to Commercial Operation

NR(4) - 4


Recent Turbine and Boiler

Design Enhancements

To Reduce Capital Costs or Improve Efficiency

■ Turbine Enhancements - Increased Output

From

● HP / IP Material Advances

● Longer LP Turbine Blades

■ Boiler Enhancements

● Proven Supercritical Performance (Asia &

Europe)

● Combustion Control Improvements

NR(4) - 5


Design Enhancements to Meet New

Environmental Constraints

■ In Response to New NOX Limits

● Demonstrated SCR Experience to

0.09 lbs / MBtu

■ In Response to New SO2 BACT Levels -

Commercial Maturity for

● Wet FGD

● Spray Dryer Absorber

● Circulating Dry Scrubber

NR(4) - 6


Design Enhancements to Meet

New Emission Limits

Tougher SO2 Limits (Assuming Western Coal)

■ Dry Scrubbers and New Fabric Filters Offer

● Lower Capital Costs

● Greater Secondary Removal

● Clearer Plume

● Less Corrosion

■ Polishing Scrubbers Provide Added Removal in

Sensitive Areas

NR(4) - 7


Representative New Coal

Plant Configuration

■ Plant Characteristics - Assuming Western Coal

● Single Unit Site - 500 to 750 MW

● Subcritical PC Boiler

● Tandem Compound Four Flow Turbine

● SCR for NOX Control

● Spray Dryer Absorber With Fabric Filter for SO2

Control

● Coal Unloading Facilities to Accommodate Delivery

by Rail or Conveyor

● Mechanical Draft Cooling Tower

■ Construction Cost of Approximately $1,200 - $1,400 / kW

■ Net Plant Heat Rate of 9,400-9,500 Btu / kWh

NR(4) - 8


Ways to Minimize New Coal

Development / Construction Costs

■ Two-Unit Sites Reduce Capital Costs per

kW by Approximately 6% and Fixed O&M

by 25-30%

■ Use of Existing Coal Handling Facilities

May Reduce Capital Costs by as Much as

$50 / kW

■ Use of Existing Site May Allow Modification

of Existing Permits, Consideration of Net

Emissions and / or Reduced Lead Times

NR(4) - 9


Can Private Coal Generation Earn

Combined Cycle Returns

Private Development Drivers

Market

Timing

Price of

Natural Gas

Market

Mix

Price of

Coal

Government

Incentives

Environmental

Issues

NR(4) - 10


Case Study Analysis

■ Using B&V’s Data Base of Construction Costs

and Performance Estimates

■ Using Financing Cost Assumptions from

Independent Engineering Assignments

■ Using Electric and Gas Market Price

Forecasts from Recent Consulting

Assignments

● For the Somewhat Extreme Markets of California

and the Mid Continent Area Power Pool (MAPP)

NR(4) - 11


Market Timing

■ New Coal Generation Is Not Competitive

in Markets With Sufficient Capacity

■ The Need for Additional Generating

Capacity Is Worth $60-$105 / kW-Year

Based on the Long-Run Marginal Cost of

New Combustion Turbine Capacity

NR(4) - 12


Existing California Market Mix

California Capacity by

Prime Mover / Fuel - 2000

Coal Steam

8%

Oil / Gas Steam

34%

Other

39%

Nuclear

10%

Combined Cycle

5%

Combustion

Turbine

4%

NR(4) - 13


Existing MAPP Market Mix

MAPP Capacity by Prime

Mover / Fuel - 2000

Other

11%

Oil / Gas Steam

2%

Coal Steam

59%

Nuclear

12%

Combustion

Turbine

16%

Combined Cycle

0%

NR(4) - 14


Supply

Generation Supply Curve

Demand

Load Duration Curve Characteristics

Supply (MW)

Load (MW)

MAPP

California

Price $/MWh

0 100

0 Cumulative % Time

Price

Market Clearing Price

Coal Plant Revenue

Is Dependent on

the Market

Price ($/MWh)

California

MAPP

0 100

Percentage of Time

NR(4) - 15


Delivered Fuel Price

Assumptions in 2005 ($/MBtu)

■ Gas

● MAPP - $3.60 + 60% - 25%

● California - $3.90 + 60% - 25%

● 2.5% Escalation

■ Coal

● MAPP - $0.64

● California - $1.25

● 2.0% Escalation

NR(4) - 16


New Entrant Financing Assumptions

■ 17-Year Debt Term

■ 60 / 40 Debt-Equity

■ 20-Year Equity Return

Period

■ 8% Interest

■ 15% Return on Equity

■ 39% Effective Income

Tax

■ 10% Coal Indirects

■ 20% Combined Cycle

Indirects

■ $550/kW Construction

Cost

■ 6,900 Btu/kWh Heat

Rate

NR(4) - 17


Observations Regarding the Competitive

Costs of New Coal Plants in California

and MAPP

■ The Market Offers Nearly 20% Higher Total

Revenues in WSCC

■ However, if Coal Prices Are Over 90%

Higher, Any Market Advantage Is Lost

■ The Threshold Construction Cost of a New

Coal Plant in California or MAPP Is

Approximately $1,000 / kW

NR(4) - 18


Factors That Can Alter the Threshold

Construction Cost of New Coal Plants

■ Alternative Gas Price Assumptions

■ Competitive Coal Pricing

■ New Environmental Rules

■ Financing Costs / Desire for Price Stability

NR(4) - 19


Private Developer Economics

Threshold Construction Cost for New Coal Fueled Capacity

$1,800

$1,600

$1,600

Construction Cost ($/kW)

$1,400

$1,200

$1,000

$800

$600

$400

$850

$750

$1,000

$1,000

$1,400

$200

$-

Low Gas Case Base Case High Gas Case

MAPP

California

NR(4) - 20


Regionally Competitive Coal Supports

Higher Construction Costs

■ Use of Low Cost, Mine Mouth Coal Priced

40 % Below the Region Supports an

Additional $200 - $300 Per kW in

Construction Costs

■ New Generation at Existing Sites Offer

Opportunities to Renegotiate Coal Supply

Contracts for Existing Generators

NR(4) - 21


Should Waste Coal Be Considered in

Developing a Competitive New Coal Plant

■ Waste Coal Properties Vary Greatly

● Lower Btu Coals Require Proportionately Large

Material Handling Facilities and Boilers

● Additional Environmental Controls, Such as

Polishing Scrubbers for High Sulfur Petroleum

Coke, May Be Required

■ At Best, the Capital Cost Premium Is $200 Per kW

■ If the $200 Capital Cost Premium Can Be Offset by

a Fuel Price Advantage in Excess of 50¢ to 60¢

Per MBtu, the Use of Waste Coal Should Be

Considered

NR(4) - 22


Impacts of New Environmental Rules

■ Impacts Must Be Considered From a Market-Wide

Perspective

■ Existing Coal Plants May Spend Much More to Comply

Than New Coal Plants

■ Black & Veatch Estimated Impacts of Phase II SO2 Limits

and the NOX SIP Call in the MAIN / ECAR Market

● Assumes $4,500 / Ton NOX Allowance Cost

● Assumes $150 / Ton SO2 Allowance Cost

● MAIN / ECAR Market Prices Rise $5-$6 / MWh

● New Coal Plant Cost of Allowances


A New Twist on

Traditional Development

Desire for

Price

Stability

Is Pushing

Regulated Utility

and Public Power

Interest in Coal

NR(4) - 24


Average Price of Gas vs Coal

Average Spot Prices

7.00

6.00

5.00

Henry Hub Gas

PRB Coal

Central Appl. Coal

4.00

3.00

2.00

1.00

0.00

1Q-95

3Q-95

1Q-96

3Q-96

1Q-97

3Q-97

1Q-98

3Q-98

1Q-99

3Q-99

1Q-00

3Q-00

1Q-01

3Q-01

$/MMBtu

Source: EIA / Enerfax / Coal Outlook

NR(4) - 25


Regulated and Public Power Economics

Threshold Construction Cost for New Coal Fueled Capacity

$1,800

Competitive EPC Cost ($/kW)

$1,600

$1,400

$1,200

$1,000

$800

$600

$400

$1,000

$1,000

$1,150

$1,150

>$1,600

>$1,600

$200

$-

Private Developer Regulated IOU Public Power

MAPP California

* Expected Natural Gas Prices

NR(4) - 26


Implications for Coal Industry Suppliers

■ A Lot of New Coal Plants Will Be Studied

and Initially Developed

● Private Financing Will Dictate the Use of

Large Plant Designs, The Use of Multiple

Unit or Existing Sites and Access to Very

Competitive Coal Prices

● Public Utilities May Still See Value in

Smaller Single Unit Plants

NR(4) - 27


Implications for Coal Industry Suppliers

■ The Probability a Plant Will Proceed

Depends on the Electric Market Which

Depends on Gas Prices and the Need for

New Generation

■ Delivered Coal Prices Are a Key Determinant

As Well


Good Site Selection is Crucial

NR(4) - 28


IGFC

(EAGLE PROJECT)

Mr Eiki Suzuki

Assistant Manager, Coal Gasification ong>Groupong>

Wakamatsu Coal Utilization Research Center

Electric Power Development Co., Ltd (EPDC)

Japan


Abstract

High-efficiency direct power generation technologies, such as molten carbonate fuel cells

(MCFCs) and solid oxide fuel cells (SOFCs) are expected to advance into practical use in

the 21st century. To take advantage of coal as a fuel-cell fuel, coal should be supplied

after being converted to gas. Oxygen-blown entrained bed gasification is regarded as

optimum due to the high concentrations of carbon dioxide and hydrogen as a combustible

and the high per-unit calorific value of coal gas. The objectives of our project "EAGLE"

are to develop optimum coal gasifier for fuel cells and to establish a clean-up system

which purifies the gas to a level acceptable for fuel cells. A feasibility study of integrated

coal gasification fuel cell combined cycle (IGFC) was conducted in fiscal year 1995,

supporting tests to obtain data necessary for coal gasifier design in fiscal year 1995-1996,

and basic and detail design of a pilot plant for processing 150 tons of coal per day in

fiscal year 1996-1997. The construction work was started at the test site, the Wakamatsu

Operations & General Management Office, and to manufacture the gasifier and other

main facilities were also started in 1998. Operation is scheduled to commence in fiscal

year 2001. This paper describes the performance of IGFC using MCFC and the status of

the pilot plant.

- 3 -


IGFC (EAGLE Project)

Hideo Maruyama

Clean Coal Technology Center

New Energy And Industrial Technology Development Organization

Eiki Suzuki

New Energy & Technology Development Department

Electric Power Development Co., Ltd.

1. Introduction

Development of high efficiency direct power generation technologies, such as molten

carbonate fuel cells (MCFC) and solid oxide fuel cells (SOFC), is currently being

promoted since they are expected to become next-generation power generating

technologies. Meanwhile, coal is also expected to become a more important energy

resource since it has abundant reserves that are more evenly distributed territorially than

those of other energy resources. The ash contained in the coal is the greatest obstacle

when coal is used in fuel cells. Thus the coal must be supplied to fuel cells after

converting it into an ash-free fuel gas. The objectives of this project are to develop an

optimum coal gasifier for fuel cells and to establish a clean-up system which purifies the

gas to a level acceptable for fuel cells. Table 1 shows the development schedule. A

feasibility study of the integrated coal gasification fuel cell combined cycle (IGFC) was

conducted in fiscal year 1995, supporting tests to obtain data necessary for coal gasifier

design in fiscal years 1995 - 1996, and basic and detail design of a pilot plant for

processing 150 tons of coal per day in fiscal years 1996 - 1997. The construction work

was started at the test site, the Wakamatsu Operations & General Management Office,

and to manufacture the gasifier and other main facilities were also started in 1998. The

operation tests are in progress since the construction work was completed at the end of

June 2001. This paper describes the performance of IGFC using MCFC and gives the

status of construction of a pilot plant.

Table 1 Development Schedule

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Feasibility study & Supporting test

Design

Construction

Operation

Evaluation

- 4 -


2. Performance of IGMCFC (in 1995)

2.1 Outline of the System

The integrated coal gasification MCFC combined cycle (IGMCFC) is composed of a coal

gasification unit, gas clean-up unit, MCFC unit, and power island, as shown in Figure 1.

Gasifier

Syngas Cooler

Cold Gas Cleanup

Air

ASU

Coal

Nitrogen

Oxygen

Filter

Expansion Turbine

Anode

MCFC

Cathode

HRSG

G

Steam Turbine

Heat Recovery Boiler

Air

Gas Turbine

G

Catalytic Burner