regional trends in energy-efficient coal-fired, power generation

FOREWORD

This paper has been produced by the Global Climate Committee of the International Energy Agency’s CoalIndustry Advisory Board, a body of industrial representatives independent of the Agency itself. It followson from a series of three papers on the subject of clean coal technologies for power generation. The firsttwo papers were status reviews of the available technologies, with combined cycle technologies coveredin the first paper and steam cycle technologies covered in the second. The third paper concentrated on thefactors which influence the market penetration of all the clean coal technologies defined in the previoustwo reports.

This latest paper examines, on the basis of regional surveys of electricity industry executives, thechallenges which exist to the greater market penetration of clean coal technologies for electricitygeneration, where coal has been chosen as the preferred fuel. It provides an interesting snapshot of theperceptions that industry executives have of these technologies and of the incentives that they believe arenecessary, in the light of the uncertainties, to increase the take-up of more energy-efficient coal-basedtechnologies.

The report particularly focuses on the challenges faced by the Supercritical Pulverised Fuel Technology(SCPF). Whilst most of the new pulverised coal combustion installed and commissioned during the 1990sin OECD countries is SCPF, this has been predominantly in those countries where the cost of the coal ishigher, such as Denmark, Germany, the Netherlands, Japan and Korea. The report notes that subcriticalsteam plant was still built in Australia, Canada and the USA, where coal is relatively cheap, and where theavailability and reliability of well proven technologies is valued highly as a design criterion. The economicincentive to raise plant efficiency is diminished by low fuel costs.

In the post-Kyoto context, more work is required on ways effectively to internalise the environmental costsof generating electricity. No single response option is uniquely valid; but use of flexible, cost-effective,market-based mechanisms, such as emissions trading, joint implementation (JI) and the Clean DevelopmentMechanism (CDM) would encourage the adoption of more efficient (and therefore more climate-friendly)technologies. The financial cost of carbon reduction programmes and the value of CDM or JI credits couldhelp to define the economic value to increasing coal combustion efficiencies.

This report is the work of the Coal Industry Advisory Board, an advisory body to the International EnergyAgency, with an independent work programme, of which this report is one product. The report is publishedon my responsibility as Executive Director of the International Energy Agency. It does not necessarily reflectthe attitudes or positions of the IEA or of its Member countries.

Robert PriddleExecutive Director

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REGIONAL TRENDS IN ENERGY-EFFICIENTCOAL-FIRED, POWER GENERATION

TECHNOLOGIES

TABLE OF CONTENTS

SUMMARY ................................................................................................................................ 5

1. INTRODUCTION............................................................................................................. 15

2. REGIONAL ASSESSMENTS......................................................................................... 16

2.1. OECD North America ........................................................................................... 16

2.1.1. Canada........................................................................................................... 17

2.1.2. United States ................................................................................................. 18

2.2. OECD Europe......................................................................................................... 19

2.3. Southern Africa ...................................................................................................... 20

2.4. OECD Asia/Pacific ................................................................................................. 21

2.4.1. Australia/New Zealand.................................................................................. 21

2.4.2. Japan.............................................................................................................. 22

3. REGIONAL FOCUS - ASIA/PACIFIC REGION ....................................................... 23

3.1. Survey of Independent Power Producers............................................................ 24

3.2. World-wide Experience with SCPF Technology ................................................ 25

3.3. Comparison of SCPF and Conventional PF Performance and Costs ............. 26

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4. CONCLUSIONS ............................................................................................................... 30

4.1. OECD North America ........................................................................................... 32

4.2. OECD Europe......................................................................................................... 33

4.3. Southern Africa ...................................................................................................... 33

4.4. OECD Asia/Pacific ................................................................................................. 34

4.5. Non-OECD Asia/Pacific......................................................................................... 35

4.5.1. Survey of Independent Power Producers ...................................................... 35

4.5.2. World-Wide Experience with SCPF Technology.......................................... 35

4.5.3. Comparison of SCPF and Conventional PF Performance and Costs........... 35

APPENDICES ........................................................................................................................... 37

APPENDIX I - REGIONAL STUDIES ON EVOLUTION OF POWER GENERATION,

OECD NORTH AMERICA............................................................................. 39

I.1. The Potential for Energy Efficient, Coal-Fired Power Generation

in Canada.................................................................................................... 41

I.2. Trends in the Evolution of Energy Efficient, Coal-Fired Power

Generation Technologies in the United States .......................................... 71

APPENDIX II - REGIONAL STUDIES ON EVOLUTION OF POWER GENERATION,

OECD EUROPE .............................................................................................. 87

APPENDIX III - EVOLUTION OF POWER GENERATION, SOUTHERN AFRICA

STUDY ............................................................................................................. 105

APPENDIX IV - OECD ASIA/PACIFIC................................................................................... 123

IV.1. Regional Studies on Evolution of Power Generation, Australia

and New Zealand..................................................................................... 125

IV.2. Study on Evolution of Energy Efficient, Coal-Fired Generating

Technology (Regional Studies Asia-Pacific) .......................................... 155

APPENDIX V - INCREASING THE EFFICIENCY OF COAL-FIRED POWER

GENERATION, STATE OF THE TECHNOLOGY:

REALITY AND PERCEPTIONS................................................................... 161

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SUMMARY

For some time the CIAB has been encouraging the development and take-up of clean coal technologiesthat produce efficiencies for converting thermal energy to electricity which are a significant improvementover those technologies in wide use today. The CIAB has previously provided the IEA with its assessmentsof:

• Industry Attitudes To Combined Cycle Clean Coal Technologies, Survey of Current Status (1994),

• Industry Attitudes To Steam Cycle Clean Coal Technologies, Survey of Current Status (1995),

• Factors Affecting the Take-Up of Clean Coal Technologies, Overview Report (1996).

In 1995, the IEA responded to the conclusions of these earlier reports by requesting the CIAB to provideits view of the barriers to the greater application of energy efficient, coal-fired power generationtechnologies (“clean coal technologies”) to meet the growing world-wide demand for electricity. Inaddition, the CIAB was asked to recommend policies and measures to encourage the take-up of clean coaltechnologies, appropriate to particular regions and countries.

All of these technologies are considered clean coal technologies because they achieve a higher efficiency forconverting thermal energy to electricity than conventional pulverised coal-fired technologies (conventionalPF). As a result, they produce lower emissions of carbon dioxide and nitrogen dioxide. The SCPFtechnologies operate at higher steam temperature and pressure levels than conventional PF, thereby achievinga greater thermal efficiency. PFBC and IGCC technologies use both a steam cycle and a gas cycle to achievehigher thermal efficiencies than conventional PF.

Clean Coal Technologies

• SCPF - Supercritical Pulverized Fuel Technologies with steam conditions equal to or greaterthan 3500psig (240 bars) and 1000°F (538°C).

• IGCC - Integrated Gasification Combined Cycle including coal gasification, hot gas clean up,steam turbine and combustion turbine generation.

• PFBC - Pressurized Fluidized Bed Combustion including fluid bed combustion, hot gas cleanup, steam turbine and combustion turbine generation.

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The IEA projects a significant growth in electricity demand and coal consumption world-wide, 67% and41% respectively, between 1993 and 2010 for the “Capacity Constrained Case”, which reflects a businessas usual approach1. For the “Energy Savings Case”, which reflects lower energy consumption, electricitydemand and coal consumption increase by 46% and 32% respectively. Given the substantial globalincreases in the demand for coal, the potential therefore exists for these clean coal technologies to be usedto supply the projected demand for electricity with greater efficiency and with a significantly lowerenvironmental impact.

Surveys were taken of the electricity industry in the major OECD coal producing/coal consuming regions ofNorth America, Europe, Southern Africa and Asia/Pacific, and of the independent power producers who aredeveloping projects in the non-OECD Asia/Pacific region. This report uses these surveys to show the attitudesof the power plant operators and developers towards clean coal technologies, the barriers to their use and thepolicies and measures that might be implemented should a country or region wish to encourage a greater useof clean coal technologies.

In addition, estimates of subcritical, supercritical and advanced supercritical performance, capital costs andoperating costs in an OECD country and the non-OECD Asia/Pacific region are compared to illustrate theperformance, economic and environmental advantages of the supercritical technologies.

The surveys indicate regional differences in the attitudes towards clean coal technologies, the barriers to theiruse and the policies and measures for overcoming these barriers.

Categories of Barriers to the Take-up of Clean Coal Technologies

Financial Risk - relate to the capital and operating cost risks of a new technology and itscompetitiveness to other proven technologies firing the same or alternativefuels.

Developmental - relate to the circumstances under which a new technology must becommercialized, e.g. deregulation of the utility sector may favour a short termreturn on investment and aversion to risk, mature markets may preclude the needfor generating capacity additions and regions in which growth is occurring mayhave a limited availability of qualified manufacturers or manpower.

Operational - the regime under which a technology may be required to operate can precludeits application, e.g. demand for peaking or intermediate generating capacity,requirements for availability and reliability, environmental restrictions and theready access to coal versus other fuels.

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1. International Energy Agency, World, Energy Outlook 1996 Edition, Paris, 1996.

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OECD North America

In Canada, the two most important determining factors in the choice of new capacity cited in the surveyare capital costs and fuel costs, followed by environmental considerations, plant availability, return on thecapital invested, construction time, and the security of fuel supplies. The survey also indicates that thepotential for the take-up of the clean coal technologies in Canada is relatively low due to the limitedaddition of coal based capacity, with the expressed interest being in IGCC technology, to be installed after2006. Interest in the other technologies will be dependent upon their commercial maturity and economicsin the same time frame.

The survey highlights that the barriers to the take-up of clean coal technologies are seen as: electricityderegulation favouring gas over coal, increasing environmental limitations, increased costs and theavailability of competitively priced natural gas. Policies suggested to overcome these barriers include thefunding of a substantial portion of the related R&D and demonstrations, and a favourable tax/depreciationtreatment.

In the United States, the survey indicates that attitudes are influenced by the current lack of requirement fornew base-load capacity and the judgement that clean coal technologies have higher capital and operatingcosts than conventional PF. SCPF is judged as commercially demonstrated, while IGCC is judged assomewhat demonstrated and reliable, and PFBC is judged as unproven.

The barriers to the take-up of clean coal technologies are seen in the survey as: the availability ofcompetitively priced natural gas, the deregulation of the electricity industry, environmental limitations

Key Regional Differences and Barriers to the Take-up of Clean Coal Technologies

OECD

• limited growth in electricity demand.

• deregulation of the electricity industry impacting priorities in decision making.

• availability of competitively priced alternative fuels and their associated lower cost technologies, e.g.natural gas.

• judgement that SCPF technology is higher in cost and less reliable, despite recent experience to thecontrary.

• lack of demonstrated costs and performance of IGCC and PFBC.

• lack of knowledge concerning the costs and performance of the commercially demonstrated SCPFand the emerging advanced SCPF, IGCC and PFBC technologies.

Non-OECD

• high growth in electricity demand.

• competition and financial constraints for independent power producers who are responsible forbuilding the majority of the new capacity.

• lack of knowledge by the IPPs, as well as their engineers and financial backers, as to the costs andperformance of the demonstrated and emerging clean coal technologies.

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(including the potential for the future regulation of CO2 emissions), and the poor public and political imageof coal, despite the promise of significant improvements in efficiency and environmental performance.Policies suggested to overcome these barriers centre on the better marketing of the advanced technologies byproviding more information on risks and costs, and financial incentives to overcome capital and operatingrisks.

OECD EUROPE

In Europe, the attitudes of the utility sector were solicited and the following 13 OECD member countriesresponded: Austria, Belgium, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Netherlands,Norway, Spain and the UK. As a consequence of the on-going transition of the industry from one ofmonopolies to a deregulated competitive market, power companies have redefined their previouslypolitically-based strategic objectives to economic ones like return on investment and capital costs. At thesame time, the survey indicates that environmental considerations are expected to continue to play animportant role in the future choice of generating capacity. Although some SCPF units have been installed,notably in Denmark, the expectation for the installation of new coal-based capacity over the next 10 yearsis low. Any coal-fired capacity that is built is likely to be SCPF technology. After 2005, the choice of cleancoal technologies will be dependent upon their state of development at that time.

The survey suggests that main barriers to an enhanced take-up of clean coal technologies are economic innature (e.g. competitively priced natural gas where it is available, and high capital costs). While SCPFtechnology is generally accepted as a proven technology, a sceptical view of the maturity of the PFBC andIGCC exists, except in those countries already hosting clean coal technology demonstration plants.Furthermore, the survey indicates that coal is seen to have a public/political image problem in Europe.Proposals suggested to overcome the barriers to the take-up of PFBC and IGCC include political supportfor the continued development and dissemination of clean coal technologies through subsidies, financingor funding, and a preferential treatment in the market place. A better dissemination of the demonstrationplant locations is also seen to constitute an effective way of proving their commercial readiness to abroader audience. Finally, suggestions to overcome environmental barriers (including public and politicalimage problems) centre on providing more information on the positive attributes of using coal as a fuel(e.g. coal’s large, geographically widespread and cost competitive resource base).

SOUTHERN AFRICA

The Southern Africa assessment presents its author’s opinion of the views of developing countries whoseprimary emphasis is on regional development and the role that power generation plays in thatdevelopment. Limited information is presented for 15 sub-Saharan Africa countries, while more detailedinformation is presented for the Republic of South Africa. The perspective from the Southern Africaregion is fundamentally different from that for the developed OECD countries. Development is focusedon local and regional issues, and attempts to maximise international co-operation to ensure thatdevelopment is optimised. A desired component of this international co-operation is for the developedcountries to assume the financial risk associated with the higher cost of the early demonstrations of cleancoal technologies. In this region, electrification is viewed as a clean coal technology because of itsbeneficial impact in reducing pollution related to the urban use of coal.

The report indicates that the most significant barrier to the take-up of clean coal technology is the excessof generating capacity which is expected to exist until after 2010. It suggests that other potential barriersinclude: concerns about reliability and higher operating costs, limited local skills and infrastructure, andcompetition from other fuels such as hydro, gas and possibly nuclear. It argues that options open to both

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governments and industry to overcome these barriers, from a developing nation’s point of view, focus ondevelopment. They include the means to catalyse economic growth, the facilitation of demonstration/pilotprojects, the funding by the developed nations of a premium for the installation of clean coal technologies,demonstrations in developing countries, a robust programme for disseminating information on thetechnologies and the development of human capabilities.

OECD ASIA-PACIFIC

The surveys reveal that attitudes towards clean coal technologies in Australia and New Zealand are dominatedby the competitive market place and the current over-capacity in generation. As a result, clean coaltechnologies are not under active consideration in either country. However, if that situation were to change,the surveys indicate that choices would be based on the following factors (in order of importance): therequired return on investment, environmental and political considerations, and capital costs. Underenvironmental factors, the emissions of concern in their order of importance were CO2, NOx, SO2 and thenothers.

Where coal technology is under consideration for new capacity, subcritical PF is the technology of choiceto the year 2000. IGCC is projected to be introduced from 2005 and will become the preferred alternativeby 2010. AFBC and PFBC are thought to have a limited application.

The barriers to the take-up of the clean coal technologies in Australia and New Zealand are seen as beingdirectly related to the competitive situation in the electricity industry. The barriers centre on whether theclean coal technologies can provide an acceptable return on investment, have competitive capital costs, havea reduced construction period, be competitive with gas-fired generation and be proven reliable for unit sizesgreater than 500 MW, as well as a lack of information on the technical and cost characteristics of thetechnologies. Beyond the competitive/economic issues, environmental concerns are also seen to have astrong influence on the take-up of new technology. The survey suggests that there is a need for a betterdissemination of pertinent information on the technical and cost factors relating to clean coal technologies.

In Japan, a number of clean coal technologies have been installed and they will play a major role in thecoal-fired capacity being planned, especially advanced SCPF and PFBC. Environmental regulation in Japanis becoming increasingly severe. The Japanese Government has supported the take-up of flue gasdesulphurisation technology by establishing shorter depreciation periods and it often provides financialsupport for the demonstration of clean coal technologies. However, the report suggests that recent moves toderegulate the electricity industry in Japan could constitute a new barrier to clean coal technologies in Japanas the cost factor and increased competition is causing the utilities to become more conservative in theirchoice of clean coal technologies and less able to accept the long-term returns associated with newtechnologies.

REGIONAL FOCUS- ASIA/PACIFIC REGION

The non-OECD portion of the Asia/Pacific region is a major developing area with countries like China andIndia. Independent power producers (IPPs) will install much of the additional generation in this region.

SURVEY OF INDEPENDENT POWER PRODUCERS

The attitudes of the IPPs toward clean coal technologies will be a critical element in their evolution in theregion. In order to benefit from the insights which IPPs have gathered as a result of their experience to date

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in private power projects and business development in the newly industrialising countries, a telephone surveywas conducted. Reliability, the cost of technology, and financing constraints were voted the most importantfactors influencing technology decisions. The next most important factors were government regulation,maintainability, technology risk and lender attitudes, technology maturity, and environmental issues.

The survey indicated that the vast majority of coal-fired projects use, or plan to use, conventional PFtechnologies for the larger plants, with some smaller projects using atmospheric fluidized bed combustion(AFBC) technology. SCPF technology is judged to be technically commercialised, but riskier and morecostly. PFBC and IGCC technologies may be used in special circumstances (e.g. with government support)in the coming years, but are unlikely to come into widespread use by the IPPs until 2005-2010 or beyond.The responses to the IPP Survey have highlighted that there is a common judgement associated with SCPFtechnologies of higher capital and operating costs and the risk of reduced plant operating reliability. Thisview exists both among the IPPs themselves and, perhaps more importantly, among their engineering andtechnology supply partners.

POTENTIAL BENEFITS OF SUPERCRITICAL TECHNOLOGIES

The CIAB believes that, if SCPF technology were to become the technology of choice for new capacity inthe Asia/Pacific region, significant economic and environmental benefits could be realised. The reductionin CO2 emissions over the economic life of these plants would be measured in billions of tons and thiswould be achieved without constraints on energy and economic growth. Significant reductions over the lifeof the plant would also be realised for other emissions of concern, such as SO2, NOx, and particulates.

Potential Benefits of Supercritical Pulverized Fuel Technologies

• SCPF technology is in wide commercial use throughout the industrialized world.

• Reliability and availability of SCPF and conventional PF units have been shown to be equivalent.

• Significant environmental benefits over the life of a plant can be realized if SCPF technology isutilized.

• CO2 reductions over the economic life of the plants would be measured in billions of tonnes ifSCPF comes into widespread use.

Independent Power Producer Survey Results

• Factors most influencing the choice of technology:

• reliability;

• cost;

• financing constraints.

• Environmental constraints are a lesser concern.

• Sub-critical pulverized fuel is the technology of choice.

• Clean coal technologies are judged to be unproven and/or more costly and less reliable.

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SCPF technology is in wide commercial use throughout the world and there are a number of advancedSCPF units with steam conditions of 600°C and 240 bar under construction or in the early years ofcommercial operation. The CIAB considers that experience over the past decade shows that the reliabilityand availability of the SCPF can match or better the level achieved by conventional PF technology. Earlyindications are that advanced SCPF units will achieve similar levels of performance.

An analysis commissioned by the CIAB estimates that the SCPF capital costs (excluding any owner orfinancing costs) and operating costs are not significantly different to those of conventional PF technology.SCPF operating costs are generally lower, but are influenced by fuel costs.

The CIAB believes that, despite the rather negative attitude of IPPs towards the take-up of the clean coaltechnologies, SCPF technology has environmental advantages and can be argued to be generallyeconomically competitive. One difficulty is that these circumstances may not apply in all the areas whereIPPs are active in the Asia/Pacific region. Costs have to be judged against a background of intensecompetition between IPPs to be the lowest bidder for the construction of power plants. This has driventhe cost of conventional PF technology to such low levels that it is unlikely to be matched by less maturetechnologies.

Capital Costs of SCPF Technologies in non-OECD Regions

• SCPF technologies require special materials and manufacturing capabilities because of the highertemperature and pressure operating conditions.

• The capital costs of SCPF will be a function of the availability of these special materials andmanufacturing capabilities in a given region.

• Where the specialized materials and manufacturing capabilities are available, SCPF will be costcompetitive with conventional PF technology.

Economic parameters used

Plant Operating Period = 30 Years Fuel cost A = $15.20/ton, B= $40/tonPlant Operating Hours = ~ 85% availability Interest during construction = 9.8%Capacity factor =~ 80% O&M Escalation 2%Fixed Charge Rate = 13% $5/ton Waste Disposal CostsO&M (fixed) = ~ $13/kW-year

SCPF Capital and Operating Cost Study

• CIAB retained SEPRIL to prepare relative cost estimates of SCPF and conventional PF.

• Estimates were prepared for a plant of two units of 600MWe each, in an Asian location, assumingthat modern materials and fabrication capabilities are available.

• Land, development, financing and owners costs are not included.

• The cost of electricity from SCPF technologies is lower than for conventional PF, but is influencedby fuel costs and site specific issues.

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In addition, the capital costs of SCPF technologies in the non-OECD regions compared to thecost of other technologies will be affected by the local availability of manufacturing expertiseand facilities required for high temperature and pressure technologies. Therein lies the challengeto governments and others who would wish acquire the environmental benefits of a maturetechnology that may not be competitive under certain circumstances.

CONCLUSIONS

The results from the surveys and the cost estimates for the OECD and non-OECD regions allows forconclusions to be drawn which can be used by governments and others to encourage the take-up of cleancoal technologies and the accrual of the associated environmental and economic benefits. The conclusionssummarised below are more fully developed in Section 4.

• Capital costs, operating costs, reliability, availability and environmental performance are theimportant factors in the selection of the technology to be used for new, additional, generatingcapacity. The relative importance of these factors may be different depending on the region. In OECDEurope environmental performance is the most important factor, while there appears to be a greateremphasis on costs, reliability and availability in the OECD North America, Southern Africa andOECD Asia/Pacific regions. In the non-OECD Asia/Pacific region, the IPPs regard capital cost,operating costs, reliability and financing constraints as the most important, with environmentalperformance a lesser concern.

• The barriers to the take-up of the clean coal technologies also vary between the regions. In the OECDregions, the barriers are: the low demand for new capacity, deregulation of the electricity markets, theavailability of competitively priced natural gas, the higher capital costs relative to natural gas-firedtechnologies and concerns about lower operating performance. The CIAB considers some concernsare based on inadequate information about the potential costs and performance of SCPF and the lackof demonstrated performance of the IGCC and PFBC technologies. In non-OECD Asia/Pacific, themain barriers are the concerns about capital and operating costs, the reliability of SCPF, the lack ofdemonstrated performance of IGCC and PFBC technologies, and the financial constraints associatedwith the IPP markets.

• The SCPF clean coal technology is a commercially demonstrated power generation technology andadvanced SCPF technology is in the early stages of commercial operation. The emerging clean coal

Conclusions

• The demonstrated and emerging clean coal technologies offer significant improvements inefficiency and environmental performance.

• Costs, reliability and environmental performance are the important factors for selecting thetechnology in the OECD regions, with a lesser concern for the environment in the non-OECDregions.

• A key barrier in all regions is the judgment that SCPF technology has higher costs and a lowerperformance, despite recent experiences in industrialized countries.

• The emerging clean coal technologies lack demonstrated cost and performance information.

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technologies, PFBC and IGCC, are in the early stages of their commercial demonstration and thereliability and economics of these technologies should be proven before 2005 - 2010.

• The demonstrated and emerging clean coal technologies offer significant improvements in efficiencyand environmental performance compared to conventional PF power generation technologies. Forexample, SCPF and advanced SCPF units have thermal efficiencies of 41 and 45 percent (LHV)respectively, as compared to the 38 percent (LHV) of the conventional subcritical PF units. They alsoproduce significantly less CO2, SO2, NOx, and particulate emissions than conventional PF units (seeTable 3.3.1.). There is also no significant capital cost difference between SCPF and subcritical PFunits, and the overall cost to produce a kilowatt hour from the SCPF units is less (see Figures 3.3.1through 3.3.4.).

• There is evidence suggesting that the early problems with SCPF technologies have, for the most part,been overcome. However, the IPPs consider this technology to entail greater capital costs andoperational risks. They will continue to favour technologies which they consider to have the lowestcapital and operating costs, and they are reluctant to consider SCPF technology on these grounds (seeSection 3.1). The CIAB considers that the recent experience with existing units indicates that thereliability of SCPF units are comparable to conventional PF units (see Section 3.2.). Althoughadvanced SCPF technology is a commercially available technology, it is only now entering commercialapplication and not enough operating time has been accumulated to unconditionally state that itsoperation will be equivalent to conventional PF. However, early indications are very promising.

• The CIAB recommends that SCPF be given serious consideration as best practice for coal-fired powergeneration, especially as a technology for developing countries.

• The demonstrated (SCPF) and the emerging (PFBC and IGCC) clean coal technologies are gainingwider acceptance in some OECD countries such as Denmark, Germany, Japan, and the US. However,financial constraints and judgements of relative risk have deterred them from being considered forcapacity additions in developing countries where much of the growth in electricity demand and coalconsumption is forecast to occur.

Policies and Measures

The CIAB recommends the following options for the private sector and governments to jointlyovercome the barriers to the take-up of clean coal technologies:

• disseminate information on the attributes of coal as a reliable, readily available, cost competitiveand environmentally compatible energy source.

• disseminate information on the attributes of clean coal technologies and their ability to improvethe performance, economics and environmental aspects of coal use.

If a government wishes to intervene directly to advance the take-up of the emerging clean coaltechnologies, it might offer financial incentives aimed at overcoming the incremental technologicaland economic risks only associated with the early commercial applications of the emerging cleancoal technologies.

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The following policies and measures to overcome the barriers to the take-up of clean coal technologies havebeen identified in the surveys:

• The CIAB recommends that the private sector and governments should undertake a co-operative effortto disseminate information on the role of coal as a reliable, readily available, cost competitive andenvironmentally compatible energy source.

• The CIAB recommends that the private sector and governments should undertake a co-operativeeffort to disseminate information on the attributes of clean coal technologies and their ability toimprove the performance, economics and environmental aspects of coal use. The private sector andgovernments should undertake co-operative technology programmes to communicate theperformance and cost details of the fully commercialised SCPF technologies and which specificallytarget the governments of the developing countries, the IPPs, the architects and engineering firms, andthe financial institutions that support them.

• The CIAB recommends that, if a government wants to intervene directly to advance the take-up ofthe emerging clean coal technologies (advanced SCPF, PFBC and IGCC), it might offer financialincentives aimed at overcoming the incremental technological and economic risks and, in this way,take advantage of their superior performance and environmental benefits.

• The CIAB recommends that these financial incentives be associated only with early commercialapplications and not be applicable to commercial deployment of the technologies beyond these earlyapplications. These financial incentives may include:

• direct project funding;

• loan guarantees;

• preferential treatment in the market place;

• innovative financing arrangements designed to encourage the utilisation of the clean coaltechnologies, e.g. specialised import/export duties and follow-on financing;

• specialised tax and/or depreciation treatment;

• support for research, development and demonstration programmes;

• streamlined permit requirements.

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1. INTRODUCTION

The Coal Industry Advisory Board (CIAB) has produced a series of three papers on industry attitudestoward clean coal technologies for power generation and the factors affecting the take-up of thesetechnologies. As a result of the information presented in these papers, the IEA Secretariat has requestedthe CIAB to provide its perspective on the potential for the electricity industry to take-up advanced, energyefficient, coal-fired power generation technologies (hereafter referred to as “clean coal technologies”) inthe near and medium time frame. This report presents a region by region assessment of the evolution ofthese energy efficient, coal-fired technologies by identifying the attitudes towards them, the barriers totheir take-up, and policies and measures that might be adopted to overcome these barriers. The regionalassessment approach is based on the generally accepted premise that the adoption of clean coaltechnologies will be a function of differing technological, environmental and economic constraints fromregion to region. While actions on these policies and measures may involve many players, the IEA isparticularly interested in the CIAB’s views on those actions which governments and industry mightconsider.

The CIAB solicited the views of its members as well as others with electricity industry expertise withinfour OECD regions of the world: North America, Europe, Southern Africa and Asia/Pacific. PreviousCIAB studies indicated that a significant amount of the growth in electricity generating capacity wasprojected to occur in the non-OECD countries and particularly the Asia/Pacific region. As a result, theCIAB decided to devote a special effort to assessing the attitudes towards clean coal technologies held bythose independent power producers who would be most likely to construct power generation facilities inthe developing countries of the Asia/Pacific region.

The clean coal technologies assessed include:

• the installation of the more efficient steam cycle plants “Supercritical Pulverised Fuel” and“advanced Supercritical Pulverised Fuel” (collectively referred to as “SCPF”) technologies asdescribed in “Industry Attitudes To Steam Cycle Clean Coal Technologies, Survey of Current Status(OECD/IEA 1995)”.

• the development and commercial application of emerging combined cycle technologies, “PressurisedFluidized Bed Combustion” (PFBC) and “Integrated Gasification Combined Cycle (IGCC)”technologies, as described in “Industry Attitudes To Combined Cycle Clean Coal Technologies,Survey of Current Status (OECD/IEA 1994)”.

In the following discussion, clean coal technologies are considered to consist of four types at two differentlevels of commercial maturity: the demonstrated technology of SCPF and the emerging technologies ofadvanced SCPF, PFBC and IGCC.

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The Asia/Pacific region is projected to experience a significant increase in the amount of electricitygenerating capacity and conventional subcritical pulverised fuel (PF) technology is the technology that isexpected to be utilised most often. As a result, it was decided to contrast the capital costs, operation andmaintenance expenses, operational reliability and environmental emission characteristics of conventional PFtechnology with those of the commercially available SCPF clean coal technology and the emerging advancedSCPF clean coal technology.

As was deemed appropriate for each region, the assessments include:

• consideration of the growth in demand for electricity in the region and the corresponding generatingcapacity that will supply that demand, segregated by fuel type and technology to the extent possible;

• consideration of the degree of take-up of clean coal technologies before 2015;

• consideration of the likely relative capital costs and their effect on the price of electricity from theclean coal technologies compared to existing technologies (e.g. taking into account the higher ratesof return on investment required to compensate for the perceived extra risk);

• consideration of any extra environmental advantages of the newer technologies. This considerationwould need to consider the possibility of the adoption of more stringent environmental standardswithin the region in the future;

• identification of government and private-sector policies, measures and incentives that would enhancethe adoption of the clean coal technologies.

The report summarises the results of the regional assessments, the survey of IPP attitudes towards the cleancoal technologies and the comparison of conventional and SCPF technologies. The assessment for eachregion, the IPP survey and the technology comparisons are presented as appendices to this report.

2. REGIONAL ASSESSMENTS

The attitudes of power generators, both utility and independent power producers, towards clean coaltechnologies can be expected to differ from region to region because attitudes are influenced by differingtechnological, environmental and economic constraints. The following discussion is an assessment of thesediffering attitudes and their implications on the take-up of the clean coal technologies in each region.

2.1 OECD NORTH AMERICA

Regional attitudes in OECD North America were assessed by examining Canada and the United States.

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2.1.1 Canada

The attitude of the Canadian electricity utility industry towards the take-up of clean coal technologies is takenfrom a report entitled “The Potential for Energy Efficient, Coal-Fired Power Generation in Canada”(Appendix I.1). This assessment is a compilation of the responses from the utilities in Canada, whichcollectively represent almost 97% of Canada’s electricity generation and all of the existing coal-firedgeneration.

Canada is geographically extremely large and therefore a diverse nation in many respects, not the least ofall in electricity generation. Coal, natural gas and hydropower are abundant, depending on the Province inquestion. Nuclear power has been developed extensively in Eastern Canada. Since 1980, new generatingcapacity has been installed in all parts of the country embracing all “conventional technologies”, withhydro, nuclear and subcritical PF being the dominant technologies. Only one advanced technology planthas been installed during this period, a 182 MW AFBC unit in Nova Scotia in 1995.

Generating capacity is forecast to increase 2.8% by 2000, with further increases of 3.0%, 4.3% and 3.4%respectively in each 5-year period until 2015. This represents a modest annual growth rate of 0.7%, whileenergy consumption is expected to increase by 1.4% per year during the same period. Of the new capacitybeing added, 16% is expected to be coal-fired and 50% is expected to rely on natural gas. Repowering,with the addition of a gas turbine, and life extension with improved unit efficiency will also play majorroles in fulfilling new capacity requirements.

In choosing the types of new capacity, capital and fuel costs were cited as the top two determining factors,followed by environmental considerations, plant availability, return on the capital invested, constructiontime, and security of fuel supplies. In those Provinces where deregulation is occurring, the higher risk ofnot recovering costs makes the reduction of investment risk through shorter planning, design andconstruction times a key factor. CO2, the emission least able to be controlled, is considered the mostimportant environmental factor, followed by SO2, NOx and siting considerations.

The potential for the take-up of the clean coal technologies in Canada is relatively low due to the limitedaddition of coal-based capacity. The expressed interest is in IGCC technology to be installed after 2006.Interest in the other technologies will be dependent upon their commercial maturity and economic viabilityin the same time frame.

The survey indicates that the barriers to the take-up of clean coal technologies are seen as: thepostponement of long-term decisions due to uncertainties resulting from the increased deregulation of theelectricity industry, increasing environmental limitations, the costs associated with coal-fired technologiesand the increasing complexity of financing arrangements. The complexity of a deregulated market, wheregas is expected to be very competitive with coal, is also expected to be a barrier.

In those locations where gas is readily available and competitively priced, it is expected to act as a barrier tothe take-up of clean coal technologies. In addition, the survey indicates that proof of performance in the areasof environment, reliability, operability and power cost on a commercial scale in a utility environment isneeded. Similarly, the capital cost and construction time of the clean coal technologies must be reduced.Proposals under consideration to control/tax greenhouse gases are seen as limiting the opportunities for coalbased technologies.

Government policies suggested to overcome these barriers include the funding a substantial portion of up-front R&D and demonstrations consistent with long-term environmental policies, and a favourabletax/depreciation treatment for environmentally sound technologies requiring penetration assistance.

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2.1.2 United States

The attitudes of electricity producers in the US towards the take-up of advanced, energy efficient, coal-fired technologies is assessed in the report entitled “Regional Trends in the Evolution of Energy Efficient,Coal-Fired Power Generation Technologies in the United States” (Appendix I.2). The assessment is basedon published information reporting the results of surveys of the electricity utilities and independent powerproducers’ attitudes towards clean coal technologies. Since 1986 the US Department of Energy (DOE) hasbeen administering a government/industry co-funded programme to demonstrate clean coal technologiesat a utility scale. The Clean Coal Technology (CCT) programme has resulted in a US $6.9 billion effortfor the first-of-a-kind or early commercial demonstration of the clean coal technologies that the CIAB haspreviously reported to the OECD/IEA. The attitudes reported here are influenced by the experiencesgained in the CCT program.

Kilowatt-hour sales in the US are expected to increase by 31% during the period 1995 to 2015. In the sameperiod, an increase of 22% (167 gigawatts (GW)) in net generating capacity is expected. New capacityadditions, plus replacement capacity for retired units, is expected to total 252 GW. Coal-fired capacity isforecast to increase by 5% (or 15 GW), natural-gas and oil-fired capacity by 69% (or 166 GW), while nuclearcapacity is forecasted to decrease by 36% (or 35 GW). The majority of the nuclear reductions are projectedto occur after 2010, when most of the current plant licences expire. These projections do not reflect anychanges that may occur as a result of the deregulation of the US electricity industry.

The potential for the take-up of the clean coal technologies exists in the 252 GW of new or replacementcapacity. However, this potential is influenced by the attitudes of the user community. The opportunities forbase load units are limited before the year 2000, but increase to some extent between 2000 and 2005. The cleancoal technologies are viewed as having higher capital and operating costs relative to subcritical PF technology.Subcritical PF appears to be the coal technology of choice, despite the fact that SCPF is viewed as a proven,reliable technology. IGCC is viewed as somewhat proven/reliable, while PFBC is viewed as not proven. Astrong interest exists in life-extension and improving the performance of existing plants. In addition,deregulation is seen as delaying indefinitely the long-term decisions on additional generating capacity.

The barriers identified to the take-up of the clean coal technologies are many. Coal remains the fuel-of-choice for base load applications. Where natural gas is readily available and competitively priced, thesurvey indicates that it will continue as the fuel-of-choice for incremental capacity additions. Concernexists over the future regulation of CO2. Life cycle costs have become less important and decisions arebeing driven by short-term considerations related to financial risk. Coal continues to have a poor publicand political image, even though clean coal technologies offer the promise of significant efficiencyimprovements and a reduced environmental impact.

Policies and measures suggested centre around two issues - the dissemination of technology information andeconomic incentives. The survey indicates that the electricity utility industry has major concerns about thecommercial status, costs and reliability of clean coal technologies and SCPF in particular. A better job needsto be done to market the clean coal technologies by providing more information on the risks and the costs.This programme should be targeted at non-utility generators in view of their future role in providing newcapacity additions. Finally, without some programme of cost sharing to reduce risks, clean coal technologiesare unlikely to be taken up to any significant extent before the year 2005. Financial incentives that have beenexplored are subsidies and a special tax/depreciation treatment. Although they remain under consideration,the US Government has enacted no such incentives.

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2.2 OECD EUROPE

In Europe, the attitudes of 16 OECD member countries were solicited and the findings are contained in thereport entitled “Regional Studies on Evolution of Power Generation, OECD Europe” (Appendix II). Austria,Belgium, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Netherlands, Norway, Spain and theUK responded to the request for information and these 13 countries represent OECD Europe for purposes ofthis report. In addition, information was requested for the 20-year period from 1995 through to 2015.However, not all respondents were willing to provide information for the 2010-2015 timeframe and those thatdid had strong reservations about the reliability of the data. Therefore, the time frame for OECD Europeinformation is 1995 through to 2010.

The OECD Europe electricity industry expects a fairly constant load growth over the period from 1995 to2010, with capacity growing by some 16% and energy use increasing by 27%.

As a consequence of the on-going transition of the industry from one of monopolies to a deregulatedcompetitive market, power companies have redefined their earlier, politically based, strategic objectives(technological reliability/availability, fuel flexibility and use of indigenous fuels) to economic ones likereturn on investments and capital costs. At the same time, environmental considerations are expected tocontinue to play an important role in the future choice of generating capacity.

European power companies expect oil to lose ground as an energy source in Europe over the next 15 years,while coal and nuclear are expected to be stable and hydropower should see a small increase. Capacity basedon renewable fuels are forecast to enjoy a significant increase but will remain an incremental energy source.

Natural gas fired technologies, with their relatively low capital costs and environmentally friendly image, areexpected to supply most of the growth. This is remarkable because even though the survey indicated thatmost European power companies held the view that “Europe is becoming too dependent on imported naturalgas”, they still plan to select natural gas as their fuel for new capacity.

In comparison to gas, the expectation for the installation of new coal-based capacity is low. Coal-firedcapacity that will be built over the next 10 years will most likely be SCPF technology. After 2005, the choiceof clean coal technologies will be dependent on their state of development at that time.

The main barriers to the enhanced take-up of the clean coal technologies are seen as economic in nature (e.g.high capital costs) and, except for those countries already hosting clean coal demonstration plants, there is asceptical view of the maturity of PFBC and IGCC technologies. Furthermore, coal is viewed as having aproblem with its public/political image in Europe.

Various proposals have been put forward by the power companies to overcome the barriers to the take-up ofclean coal technologies. With respect to the high capital costs, suggestions made include political support forthe continued development and dissemination of clean coal technologies through subsidies, financing orfunding. Preferential treatment in the market place of the electrical output from clean coal technologies isanother possible approach.

When it comes to overcoming the scepticism on the maturity of PFBC and IGCC technologies, the fact thatthe countries hosting these technologies have a strong confidence in their virtues may indicate that a betterdissemination of demonstration plant locations could constitute an effective way of proving their commercialreadiness to a broader audience.

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Finally, the proposals suggested for helping to overcome environmental barriers (including public andpolitical image problems) include providing more information on the positive attributes of coal as a fuel (e.g.the large, geographically widespread and cost competitive resource base and the advanced technological stateof today’s coal mining and coal usage facilities). Furthermore, the implementation of closed handling systemsat harbours and power plants is suggested as being beneficial for the image of coal.

2.3. SOUTHERN AFRICA

The Southern Africa assessment presents its author’s opinion of the views of developing countries whoseprimary emphasis is on regional development and the role that power generation plays in that development.Limited information is presented for 15 sub-Saharan Africa countries, with more detailed information for theRepublic of South Africa, in the report entitled “Evolution of Power Generation, Southern Africa Study”(Appendix III). During 1995, South Africa accounted for 76% of the generating capacity of the region andproduced 83% of the electricity generated. As a result, the regional information is to be considered qualitativeat best.

The perspective from the Southern Africa region is fundamentally different from that for developed OECDcountries. Development is focused on local and regional issues, and on attempts to maximise internationalco-operation to ensure that development is optimised. This entails securing clean coal technologies duringdevelopment, with the incremental costs above those of conventional technology being borne by thedeveloped countries. This approach has been referred to as “Activities Implemented Jointly” in the contextof reducing the environmental impact.

The 1995 electricity supply and demand situation for the 16 sub-Saharan African countries is one ofsignificant oversupply. The region has a total installed capacity of 46 GW and electricity production totalled208 Million MWh, which represents 52% of the potential production. Under current projections, it is unlikelythat additional capacity will be required in the region before the year 2010. Excess capacity in the region maybe optimally utilised via the Southern African Power Pool. However, issues such as the reliability of longtransmission lines, coupled with individual national priorities, could result in additional capacity being builtbefore 2010. Any increase in capacity will, in all likelihood, be met predominately by coal in South Africaand by hydro in the other countries in the region. In addition, South Africa has introduced a demand sidemanagement programme as an alternative to additional capacity.

In spite of the oversupply situation and since future growth is highly uncertain, supply side options are beingevaluated for future applications. Clean coal technologies are being evaluated with the objective of reducinglead-times, capital costs, operating costs and the environmental impact and for optimising unit size and loadfollowing capability. Environmental concerns focus on the local and regional impact, with a lower priorityput on the global impact.

Clearly the most significant barrier to the take-up of clean coal technologies is the excess of generatingcapacity, which is expected to continue until after 2010. Other potential barriers include: judgements ofunreliability and higher operating costs, limited local skills and infrastructure, and competition from otherfuels such as hydro, gas and possibly nuclear. Also the existing capacity is relatively new (11-15 years old)and therefore there is only a low potential for retirement and replacement with clean coal technologies.

With the expectation that new capacity will not needed until after the year 2010, a number of options are opento both governments and industry to overcome the barriers from a developing nation’s point of view. These

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include means to catalyse economic growth, funding of the premium for the installation of clean coaltechnologies by the developed nations, demonstrations in developing countries, a robust program fordisseminating information on the technologies and the development of human capabilities in developingcountries.

2.4. OECD ASIA/PACIFIC

The assessment of the OECD Asia/Pacific region consists of a compilation of attitudes in three countries:Australia, New Zealand and Japan.

2.4.1. Australia/New Zealand

In Australia and New Zealand, governments have or are in the process of deregulating the electricity industryand promoting competition between utilities and open access for new generators. This competitiveenvironment, combined with excess reserve margins in some areas, means that there is currently significantuncertainty as to the type and timing of new, additional, generating plant.

The assessment of the take-up of clean coal technologies reflects this change in the electricity industry andis presented in detail in the report entitled “Regional Studies On Evolution of Power Generation, Australiaand New Zealand” (Appendix IV.1).

Load growth in Australia and New Zealand is expected to average 2% per year to 2015. This low predictedgrowth, coupled with existing excess reserve margins in some areas and the highly competitive situationwhich is developing, is restricting prospects for new large coal-fired base load plants, although there areopportunities for new generation initiatives in the near future. New generation will be incremental in natureand, with the deregulation of the Australian gas industry, will favour gas as the fuel-of-choice. Much of thecoal capacity has recently been retrofitted and further refits are scheduled before the year 2000. Theseretrofits consist of minor technology advances and it is unlikely that they will use any clean coal technologysuch as IGCC.

Before deregulation, the energy mix was under the ownership and control of the governments of the twocountries. Now, however, the competitive market will dictate the mix of capacity additions. In thiscompetitive environment, organisations are somewhat reluctant to divulge their capacity addition plans,but an estimation of minimum likely new generation has been made, based on a number of sources andstatements in interviews. Likely new generation in Australia is projected to total 16.6 GW by the year2015, with 2.2 GW of it coal, 6.8 GW gas, 5.6 GW renewables, and 2 GW uncommitted. There is 1.5 GWof gas generation available in eastern Australia and 1.0 GW in western Australia, which is expected to beutilised by 2000. Installation of gas-fired generation after 2000 will depend on the location and thedevelopment of the production and transmission systems. Likely new generation in New Zealand isforecast to total 1.7 GW by the year 2015, with 0.6 GW of it gas, 0.4 GW renewables, and 0.7 GWuncommitted.

As elsewhere, capital and fuel costs are indicated as the key factors in determining new capacity choices,particularly as deregulation has heightened the imperative that generators be competitive. Also,environmental considerations are increasingly to the forefront in capacity choices, with CO2 performanceincreasingly important.

Attitudes towards clean coal technologies in Australia and New Zealand are dominated by the competitivemarket place and, as a result, clean coal technologies are not under active consideration in either country.

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However, if this situation were to change, the survey shows that existing and potential generators wouldevaluate the clean coal technologies using the following factors (in their order of importance): requiredreturn on investment, environmental and political considerations, and capital costs. Under environmentalfactors, the emissions of concern in their order of importance are: CO2, NOx, SO2 and others. Where coaltechnology is under consideration for new capacity, subcritical PF is the technology of choice to the year2000. IGCC is projected to be introduced from 2005 and will become the preferred alternative by 2010.Atmospheric fluidized bed combustion and PFBC are thought to have limited application.

The barriers to the take-up of clean coal technologies in Australia and New Zealand are again seen to bea direct result of the competitive situation in the electricity industry and can be divided intocompetition/economic issues and technical issues. The competitive/economic barriers centre on whetherclean coal technologies can provide an acceptable return on investment, have competitive capital costs aswell as a reduced construction period, and be competitive with gas-fired generation. On the technical side,barriers to unit sizes greater than 500 MW are the lack of proven reliability and a lack of information onthe technical and cost characteristics.

Beyond the competitive/economic issues, the environment is also seen to have a strong influence on the take-up of new technology. The environmental anti-coal lobby is influencing the policy agenda, with one stategovernment in particular encouraging electricity retailers to contract for power suppliers from low carbon orcarbon-free sources.

The survey suggests that there is a need for a better dissemination of pertinent information on the technicaland cost factors relating to clean coal technologies.

2.4.2 Japan

The assessment for Japan is taken from annual reports to the Ministry of International Trade and Industry(MITI) prepared by the 10 regional electricity utilities. Data on regional demand and demand growth isreported and organised by fuel type. Both major equipment suppliers and the regional utilities providedinformation concerning the take-up of the clean coal technologies. This information has been compiled intoa report entitled “Study on Evolution of Energy-Efficient, Coal-Fired Generating Technology (RegionalStudies Asia-Pacific)” (Appendix IV.2).

The expansion of electricity generating capacity will continue to be driven, at least until the beginning of the21st century, by the concept of diversifying the fuel mix to increase the security of supplies. Power generationcapacity in Japan is expected to increase by 101 GW to the year 2010. During the period 1996 through to2005, 70.7 GW of capacity will be added, of which 10.1 GW will be hydro, 21.7 GW coal, 26.5 GW LNGplus LPG, 0.4 GW Orimulsion, 0.1 GW geothermal and 14.6 GW nuclear. At the same time oil and other gascapacity will decrease by 2.0 GW.

Clean coal technologies will play a major role in the coal-fired capacity being planned, especially advancedSCPF technology and PFBC. Candidate projects, so dubbed because all the details of the installations havenot yet been finalised, account for 4.6 GW of capacity (4.1 GW USC and 0.5 GW of PFBC). Japan currentlyhas 16.6 GW of SCPF and the largest AFBC unit in the world (350 MW), as well as a 70 MW PFBC unit.Two additional 350 MW PFBC units are at the planning stage.

Environmental regulation in Japan is becoming increasingly severe. Citizen groups are taking a more activerole in shaping agreements between the local authorities and the utilities. In some situations power plants

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have had to install a dry flue gas desulphurisation system (FGD) based on scrubbing with activated char. Thisadvanced emission control system has similar capital costs to FGD plus SCR (selective catalytic reduction)but has higher operating costs due to the activated char.

The Japanese Government has supported the take-up of the advanced FGD and SCR so far, by establishinga shorter depreciation period of 7 years as opposed to the normal 15 years. In addition, the government oftenprovides financial support for the demonstration of the clean coal technologies. However, recent moves toderegulate the electricity industry in Japan could constitute a new barrier for clean coal technologies. As aresult, the cost factor and increased competition is causing the utilities to become more conservative in theirchoice of clean coal technologies and less able to accept long-term returns.

3. REGIONAL FOCUS - ASIA/PACIFIC REGION

The selection of additional generating capacity in non-OECD countries will also have a major bearing on thetake-up of the clean coal technologies. The primary expanding market for coal over the coming decades willbe in electricity generation, especially in the developing countries of the world. An estimation of the amountof new generation required by the world to the year 2015, under a high economic growth projection, is 7.7million gigawatt hours (GWh), of which 4.5 million GWh will be required by the non-OECD countries . Coalis expected to be the fuel-of-choice for a substantial part of that generation, as it is a readily accessible energysource for many, if not all, of the developing countries. It will therefore play a major role in sustaining thegrowth now being experienced in many of the developing countries.

Environmental issues will also be a major consideration regionally, as well as globally, for these developingcountries. If coal is to play its major role, it must be utilised in an efficient and environmentally soundmanner. The evolution of clean coal technologies can make a significant contribution to the requirement forsustained growth in an environmentally sound manner. Today’s state-of-the-art, SCPF power plant has aconversion efficiency of 42% to 45% (LHV), about 5 percentage points higher than that of a subcritical PFpower plant (which continues to be the coal-fired technology selected in most developing countries).Developing countries select conventional (subcritical) PF technology because of its perceived lowergenerating cost and higher availability. However, if SCPF technology were to become the technology-of-choice for new capacity additions in these countries and in particular in the high growth Asia/Pacific region,significant economic and environmental benefits could be realised. The reduction in CO2 emissions over theeconomic life of these plants would be measured in billions of tons and be achievable without constraints onenergy and economic growth. Significant reductions over the life of the plant would also be realised for otheremissions of concern, such as SO2, NOx, and particulates.

The non-OECD portion of the Asia/Pacific region is a major developing area with countries such as Chinaand India. Since independent power producers (IPPs) will install much of the generation that will be addedin this region, their attitude towards clean coal technologies will be a critical element in the evolution of thesetechnologies in the region. The attitudes of the power plant designers, constructors and financial supportersare also important. Similarly, the building and operating costs, as well as the environmental impact, of cleancoal technologies will be important factors.

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Recognising the importance of the Asia/Pacific as the expected recipient of intense activity in theconstruction of coal-fired power plants, primarily by IPPs, over the next 20 years, and the role clean coaltechnologies might play, a report entitled “Increasing the Efficiency of Coal-Fired Power Generation, Stateof the Technology: Reality and Perceptions” (Appendix V) was prepared to address these issues. The reportconsiders the attitudes of the IPPs towards clean coal technologies, especially in respect of the SCPFtechnology, its operating and environmental potential, and its relative costs compared to conventional PFtechnology. The following discussion is a summary of the approach and conclusions of that report.

3.1 SURVEY OF INDEPENDENT POWER PRODUCERS

In order to benefit from the insights which the IPPs have gained as a result of their experience in privatepower projects and business development in the newly industrialising countries, a relatively simple surveyby telephone was conducted. The most appropriate people to respond to such a survey were identified andthe telephone interviews carried out between April and July 1996.

The survey consisted of a total of sixteen telephone interviews and/or written responses. The majority ofthose interviewed represented independent power producing companies involved in developing powerprojects in non-OECD countries. However, representatives of several power engineering/constructioncompanies and technology suppliers also participated. There was a high degree of consensus among theparticipants in their response to the questions, which makes it relatively simple to draw a number of broadconclusions, which are presented below.

The vast majority of coal-fired projects use, or plan to use, conventional PF technologies for the larger plants,with some smaller projects using atmospheric fluidized bed combustion (AFBC) technology. SCPFtechnology is viewed as technically commercialised, but riskier and more costly. PFBC and IGCCtechnologies may be used in special circumstances (e.g. with government support) in the coming years, butare unlikely to come into widespread use by IPPs until the period 2005-2010 or beyond.

The World Bank Environmental Guidelines play a major and increasing role in most countries. Some IPPshave corporate environmental guidelines, which go beyond the World Bank ones, but to go too far beyondwould raise issues of economic competitiveness.

Reliability, the cost of the technology, and financing constraints were voted the most important factorsinfluencing the choice of technology (averaging 4.6 on a scale of 1 to 5). The next most important factorswere government regulation (4.4), maintainability (4.2), technology risk and lender attitudes (both 4.1),technology maturity (4.0), and environment (3.9). Interestingly, the need for skilled operators scoredrelatively low in the poll (3.3), as the IPPs believe that it is relatively easy to find and train operators.

Most coal-fired power plants being planned or built today use subcritical PF technology and have conversionefficiencies in the range of 37-39% (LHV) basis. The responses on the future efficiency trends over the next5-10 years were mixed, although few expect increases of more than a few percentage points. Increasedoperating efficiency should be a major concern for the power producers due to its impact on operating costs.This is especially true where the power plant fuel and/or other operating costs are particularly high. Higheroperating efficiency also has a positive impact on emissions, because, on a per unit of energy produced basis,less fuel will be consumed and so less emissions will result.

The responses to the IPP Survey have highlighted that there is a common perception of higher capital andoperating costs, and a risk of reduced operating reliability, associated with SCPF technologies both amongIPPs themselves and, perhaps more importantly, among their engineering and technology supply partners.

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3.2 WORLD-WIDE EXPERIENCE WITH SCPF TECHNOLOGY

Efficiency improvements and air emission reductions for pulverised coal plant fuel are achieved with highersteam cycle operating pressures and temperatures.

• The subcritical (Conventional) steam pressure cycle with one stage of reheat at 2400 psig/1000°F(166 bar/538°C) cycle has been the dominant design in the past and continues to be the most oftenselected cycle in many countries.

• The SCPF cycle at 3500 psig/1000°F (240 bar/538°C) cycle has been used for a smaller number ofplants.

• The advanced SCPF with two stages of reheat at 4500 psig/1100°F (311 bar/593°C) is the state-of-the-art “commercially” available plant.

The nominal design efficiencies based on lower heating value and at the full load condition for these plantsare conventional~ 38%, SCPF~ 41% and advanced SCPF~ 45%. These efficiencies may vary due to localconditions such as access to cold ocean cooling water systems.

SCPF technology is in wide commercial use throughout the world and there are a number of advanced SCPFunits under construction or in the early stages of commercial operation. There are 20 units operating in theUS ranging in size from 325 MW up to 760 MW, although the greatest concentration of installed supercriticalplants is in the countries of the former Soviet Union, where 232 units are in operation. These units aredesigned at specific sizes: 300 MW, 500 MW, 800 MW, 1200 MW, and have steam conditions typically 234Bar/565°C /565°C, with some advanced designs operating at 292 Bar/649°C /649°C. In Japan, up to 60supercritical units are in operation or planned at steam pressures up to 309 Bar and temperatures to 610°C.They include the gas-fired Chubu Electric, the Kawagoe 700 MW units (309 Bar/566°C/566°C/566°C), thecoal-fired Hekinan #3 700 MW unit with main steam and reheat temperatures of 538°C/593°C and thesupercritical Mastuura Unit 2 rated at 1000 MW steam conditions of 240Bar/593°C/593°C which isscheduled to be in operation in 1997. There are 47 supercritical units operating in Europe, largely inGermany, Denmark and Italy, and 6 more are under construction in the same countries. Typical of these unitsare Esbjerg #3, with steam conditions of 245 Bar/560°C/560°C and Nordjyllandsvaerket (Aalborge), a400 MW plant with steam conditions of 240 bar/580°C/580°C which is to begin operation in 1998.

Studies on the relative reliability of coal-fired conventional PF and SCPF plants in the United States showthat the conventional units have, in the past, had better reliability during the first ten years of operation.By the time a SCPF unit was ten years old, the average outage hours caused by the pressure parts hadlevelled off at less than 500 hours/year (approximately 6%/year unavailability) for all US units, while forsubcritical units the level was the same but climbing. However, the early problems in first and second-generation supercritical boilers and steam turbines have been overcome. Experience over the past decadeshows that the reliability and availability of the supercritical cycle, after more than two decades of researchand development, can match or better the subcritical cycle for base load operation throughout the life ofthe unit.

A comparison of the reliability of 5 subcritical units and 4 SCPF units operated by the Electric PowerDevelopment Co., Ltd. in Japan during the years 1991 through 1995 reveals no significant difference betweenthe units. The definition of reliability is actual kWh produced divided by the sum of the rated capacity of theunit and the total number of hours in a year. The year by year reliability is shown in Table 3.2.

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Table 3.2.Comparison of Conventional PF and Supercritical PF Reliability

Subcritical PF Subcritical PFYear (5 Unit Average) (4 Unit Average)

1995 78.5% 76.5%

1994 73.5% 74.7%

1993 77.7% 82.1%

1992 76.6% 79.6%

1991 79.9% 77.4%

3.3 COMPARISON OF SCPF AND CONVENTIONAL PF PERFORMANCE AND COSTS

In order to assess the cost-effectiveness and environmental performance of SCPF and advanced SCPFgenerating plants compared to a conventional subcritical PF plant, an analysis of comparative performanceand cost was carried out for a plant with two 600 MW PC-fired units in a European and Asian location.

The following economic parameters were used:

Plant Operating Period = 30 Years Fuel cost A = $16.50/tonne, B= $44.00/tonnePlant Operating Hours = ~ 85% availability Interest during construction = 9.8%Capacity factor = ~ 80% O&M Escalation 2%Fixed Charge Rate = 13% $5/ton Waste Disposal CostsO&M (fixed) = ~ $13/kW-year

And the following scenarios evaluated:

(1) 2400 psig conventional (subcritical) plant with an electrostatic precipitator for particulate control andlow-NOX burners, but no post-combustion sulphur or nitrogen oxide controls, (Conventional Plant).

(2) 3500 psig SCPF plant with an electrostatic precipitator for particulate control and low-NOx burners,but no post-combustion sulphur or nitrogen oxide controls.

(3) 4500 psig advanced SCPF plant with an electrostatic precipitator for particulate control and low-NOxburners, but no post-combustion sulphur or nitrogen oxide controls.

(4) 4500 psig advanced SCPF plant with spray dryer flue gas desulphurisation system (FGD), selectivecatalytic reduction system for removal of NOx (SCR), and baghouse for particulate control (advancedSCPF w/FGD, SCR).

The analysis was carried out for two variants of capital cost and of coal price. The higher capital cost(~US$800/kW for a conventional PF plant without FGD) corresponds to that for a plant built in a developedOECD country, and the lower capital cost (~US$620/kW) to that for a similar plant constructed in a

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developing country such as China. The lower coal price (~$16.50/tonne, heating value 4,400 kcal/kg) mightbe that for a mine mouth coal plant in a developing country, and the higher coal price (~$44.00/tonne, heatingvalue 6,700 kcal/kg) might be the landed price of internationally traded coal at a coastal power plant. Theperformance of the four technologies is summarised in Table 3.3.1

When comparing plants without post-combustion air pollution controls over a 40-year operational period,mass emissions of CO2 are reduced by over 27 million tonnes for an advanced SCPF plant compared to aconventional plant. Similarly, mass emissions of SO2, NOx and particulate are reduced by over 120,000,43,000 and 432,000 tonnes respectively.

Using the state-of-the-art air pollution controls, emissions of conventional pollutants can be reduced toultra-low levels. The advanced SCPF plant equipped with a lime spray dryer to control SO2, a selectivecatalytic reduction system (SCR) to reduce NOx emissions, and a fabric filter system (baghouse) canreduce emissions to a level that is below the emissions from a conventional PF unit equipped with typicalpollutant controls. The reduction is equivalent to 736,000 tonnes of SO2, 281,000 tonnes of NOx and2,247,000 tonnes of particulate matter. The additional capital cost for these state-of-the-art controls on a600 MW unit firing low sulphur coal (less than 0.9%) would be approximately $130/kW. The emissionscould be reduced by up to ~90% while firing low sulphur coal. These would be able to satisfy the moststringent regulatory and permit requirements for SO2, NOx and particulates.

Table 3.3.1Comparison of Efficiency and Environmental Performance Between

Conventional PF, SCPF and Advanced SCPF Technologies

Fuel Cost Emission Reduction Over 40 Year LifeReduction Thousand Tonnes (% Reduction from Base)

Million US$/Year

Technology Efficiency @US$ @US$CO2 SO2 NOX Particulates

% 16.50/t 44.00/t

Conventional PF 38 Base Base Base Base Base Base

3500 psig SCPF 41 3.0 5.2 14,500 61 22 222(8%) (8%) (8%) (8%)

4500 psig Advanced SCPF 45 6.0 10.9 27,200 120 43 432(15%) (15%) (15%) (17%)

4500 psig Advanced SCPF 44 5.6 9.7 26,300 736 281 2,247w/ FGD & SCR (15%) (91%) (98%) (86%)

Note: The 4500 psig Adv. SCPF w/ FGD & SCR technology is assumed to have a 2% energy penalty.

The capital cost comparisons between the different technologies for the higher capital cost case (built in adeveloped OECD country) are shown in the following table. This also separates out those items for whichthe cost increases for the SCPF and advanced SCPF plants, relative to the conventional plant. The plantwould have two units with low NOx burners, high efficiency particulate collection equipment, once-throughsea water cooling, including the switch yard and all the facilities for a new site location, and a 60 monthconstruction schedule. The capital cost estimates include the plant equipment, structures, switchyard and coalunloading facilities. Land, development, financing and owners costs are not included.

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Table 3 3.2Capital Cost Comparison Between

Subcritical, Supercritical and Advanced Supercritical Technologies

AdvancedTechnology Cost Sub- Super- Advanced Super-critical

$/kW* critical critical Super-critical w/ FGD & SCR

Subtotal for equipment & systems that increase in cost; e.g. boiler, turbine, high pressure piping $294 $310 $323 $323

Percentage of Base Base 105% 110% 110%

Remainder of Plant $509 $501 $487 $605


Total Plant Cost $803 $811 $811 $929


* Excluding land, development, financing and owner costs.

A comparison of the cost of electricity from the conventional and clean coal technologies is shown in thefollowing figures:

Figure 3.3.1Cost of Electricity (cents/kWh)

Lower Fuel Cost ($16.50/tonne)/Higher Capital Cost Case ($800/kW)


Lower Fuel Cost ($16.50/tonne)/Lower Capital Cost Case ($620/kW)

Fuel CostsVariable O&MFixed O&MCapital Charges

ConventionalPF

SCPF Adv SCPF Adv SCPFw/FGD/SCR+ Baghouse

5.0

4.0

6.0

3.02.0

1.0

0.0


ConventionalPF


5.04.03.0

2.01.00.0

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Higher Fuel Cost ($44/tonne)/Higher Capital Cost Case ($800/kW)


Higher Fuel Cost ($44/tonne)/Lower Capital Cost Case ($620/kW)

When the higher capital cost is used in the analysis, going from conventional PF to SCPF in the lower coalprice case reduces the electricity cost by 0.08 cents/kWh, and in the higher coal price case by 0.23cents/kWh - almost a factor of three. The corresponding reductions in going from conventional PF toadvanced SCPF are 0.14 cents/kWh in the lower coal price case and 0.48 cents/kWh in the higher coalprice case.

When the lower capital cost is used in the analysis, the corresponding reductions in going fromconventional to advanced SCPF are 0.13 cents/kWh in the lower coal price case and 0.47 cents/kWh in thehigher coal price case. This implies that the choice of whether to use subcritical or supercriticaltechnologies is not very sensitive to general capital cost levels. The “super clean” advanced SCPF plantwill produce marginally cheaper electricity in the high fuel and high capital case (0.07 cents/kWh) or lowcapital case (0.012 cents/kWh) than the conventional PF plant which has only a modest level of pollutioncontrol.

Thus it can be seen that, despite the rather negative attitude of IPPs toward the take-up of clean coaltechnologies, SCPF technology has environmental advantages and can be argued to be generallyeconomically competitive in certain circumstances. One difficulty is that these circumstances may not apply


ConventionalPF


5.06.07.0

4.0

3.02.01.00.0

Fuel Costs

Variable O&MFixed O&MCapital Charges

ConventionalPF


5.06.07.0

4.03.02.01.00.0

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in all areas where IPPs are active in the Asia/Pacific region. Costs have to be judged against the backgroundof intense competition between IPPs to be the lowest bidder for the construction of power plants. This hasdriven the cost of conventional PF technology to low levels, to the extent that is unlikely to be matched byless mature technologies. In addition, the capital costs of SCPF technologies in the non-OECD regions inrelation to the cost of other technologies will be impacted by the local availability of the manufacturingexpertise and facilities required for high temperature and pressure technologies. Therein lies the challenge togovernments and others who would wish to acquire the environmental benefits of a mature technology thatmay not be competitive under a site-specific set of circumstances.

4. CONCLUSIONS

The trends in the evolution of energy efficient, coal-fired, power generation technologies are a function of theneed for new generating capacity, the attitudes of the power generators, the barriers to the take-up of thetechnologies and the policies and measures that governments and others implement to overcome thosebarriers. The factors affecting the evolution of these trends vary from region to region, both in nature andemphasis, due to economic, environmental and political differences. However, the following generalconclusions can be drawn:

• The projected growth in generating capacity:

⇒ Growth in electricity demand in OECD countries is projected to be limited. Opportunities for cleancoal technologies will be limited in those countries where other fuels, especially natural gas, areavailable and competitively priced. As a result, additional coal-fired capacity is not projected to besignificant.

⇒ Electricity demand growth in non-OECD countries is projected to be substantial and additional coal-fired capacity will play a dominate role in many countries where coal is readily available andcompetitively priced relative to other types of fuel.

• Attitudes towards the clean coal technologies:

⇒ Deregulation and competition in electricity markets tend to defer decisions on additional generatingcapacity and may favour decisions based on short-term criteria, e.g. initial capital costs may be givenmore weight in any decision than life of plant operating costs.

⇒ Environmental issues must, to an ever-increasing extent, be taken into account in power generation,and particularly for coal-fired capacity.

⇒ Natural gas-fired technologies have certain advantages for the short term as a result of lower capitalcosts, lower emissions, and lower electricity production costs, where the gas is available andcompetitively priced.

⇒ The SCPF clean coal technology is a commercially demonstrated power generation technology andadvanced SCPF technology is in the early stages of commercial operation. The emerging PFBC andIGCC clean coal technologies are in the early stages of commercial demonstration and the reliabilityand economics of the technologies should be proven before the period 2005 - 2010.

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⇒ The SCPF and emerging advanced SCPF, PFBC and IGCC clean coal technologies are being judgedto have higher capital and operating costs and unproven operating performance (reliability andavailability).

⇒ The judgement remains that coal-fired electricity generating technologies have greaterenvironmental impact than other technologies, despite the fact that the superior performance ofclean coal technologies offers a different reality and can be pointed at to dispel this perception.

⇒ Developing countries require technical and financial support from the developed countries toovercome the risks that might be associated with the emerging advanced SCPF, PFBC and IGCCtechnologies. For example, this support might take the form of joint implementation or activitiesimplemented jointly according to the UN Framework Convention on Climate Change.

• Barriers to the take-up of the clean coal technologies:

⇒ Uncertainty associated with a deregulated electricity industry and a highly competitive market place.

⇒ Increased availability of competitively priced natural gas and the lower capital costs of natural gas-fired technologies.

⇒ Lack of commercially demonstrated performance and cost competitiveness for PFBC and IGCC.

⇒ Persistence of public and political resistance to coal-fired technologies, despite the attributes of theclean coal technologies.

⇒ Environmental limitations and the judgement that they will become more stringent over time,particularly with respect to carbon emissions.

⇒ Lack of pilot/demonstration clean coal technology projects in both developed and developingcountries

• Policies and measures to overcome the barriers:

⇒ Private sector and government co-operative efforts to disseminate information on the role andattributes of coal as a reliable, readily available, cost competitive and environmentally compatibleenergy source.

⇒ Private sector and government co-operative efforts to disseminate information on the attributes of theclean coal technologies and their ability to improve the performance, economics and environmentalaspects of coal use.

⇒ Private sector and government co-operative technology programmes which communicate the detailson the performance and costs of the fully commercialised SCPF and the emerging advanced SCPFtechnologies, and which specifically target the governments of the developing countries, the IPPs, thearchitects, the engineering firms, and the financial institutions that support them.

⇒ If a country or region wanted to advance the take-up of the emerging PFBC and IGCC clean coaltechnologies, it might offer financial incentives aimed at overcoming the incremental technologicaland economic risks associated only with the early commercial applications and, in this way, takeadvantage of their superior performance and environmental benefits. These financial incentives mayinclude:

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♦ direct project funding;

♦ loan guarantees;

♦ preferential treatment in the market place;

♦ innovative financing arrangements designed to encourage the utilisation of the cleancoal technologies, e.g. specialised import/export duties and follow-on financing;

♦ specialised tax and/or depreciation treatment;

♦ support for research, development and demonstration programmes;

♦ streamlined permitting requirements.

⇒ Establish pilot/demonstration projects in both developed and developing countries through jointactions such as those proposed under the UN FCCC activities implemented jointly.

The following discussion presents specific conclusions from the regional assessments, the IPP survey and theperformance and cost comparison for the clean coal technologies.

4.1 OECD NORTH AMERICA

• Growth in generating capacity in the region until 2015 is projected to be 204 GW, of which 21 GWis expected to be coal-fired capacity.

• The attitude towards the clean coal technologies is shaped by the following factors:

⇒ deregulation is delaying long-term decisions on capacity.

⇒ little need for base load capacity.

⇒ capital costs, reliability, fuel costs and environmental constraints are key criteria for selectingtechnology for new capacity additions.

• Barriers to the take-up of the clean coal technologies are:

⇒ increased availability of competitively priced natural gas and relatively lower capital costs fornatural gas fired technologies.

⇒ high capital costs of PFBC and IGCC.

⇒ lack of commercially demonstrated reliability and operability.

⇒ lack of awareness of the attributes by potential developers.

• Policies and measures that could overcome the barriers are:

⇒ change the negative attitude of government and public towards coal.

⇒ provide financial and regulatory incentives (e.g. tax relief, specialised depreciation, financialsupport, and permitting relief for the early commercial applications - first 3 to 5 installations).

⇒ implement a programme to inform IPPs and other developers of the attributes of the clean coaltechnologies.

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4.2 OECD EUROPE

• Growth in generating capacity in this region until the year 2015 is projected to be 82 GW, of which1 GW is expected to be coal-fired capacity.


⇒ deregulation has redefined the priorities from reliability/availability to economic.

⇒ environmental limitations remain a strong consideration.

⇒ natural gas appears to have advantages in some countries where it is available and competitivelypriced.

⇒ countries with demonstration projects have a higher confidence in clean coal technologies.

⇒ SCPF and advanced SCPF are viewed as a proven technologies in some countries.


⇒ low capital costs of natural gas-fired technologies.

⇒ the opportunity for the installation of base-load, coal-fired capacity is negligible.

⇒ economic competitiveness in question.

⇒ uncertainty of the commercial status and reliability of PFBC and IGCC.


⇒ reduce capital costs through favourable financial incentives.

⇒ the harmonisation of emission limits and energy taxes.

⇒ attributes of coal should be publicised.

⇒ conduct pilot/demonstration projects in more countries.

4.3 SOUTHERN AFRICA

• Growth in generating capacity in the region until 2015 is projected to be 24 GW, of which 18 GW isexpected to be coal-fired capacity.


⇒ local and regional development takes precedent over technology choices.

⇒ coal and hydro are the preferred choices when capacity is required.

⇒ clean coal technologies are viewed favourably, but must be proven against competing options on acost, availability and reliability basis.

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⇒ no generating capacity required until after 2010.

⇒ existing capacity is relatively new.

⇒ hydro focus in the region.

⇒ judgement that operating costs are higher.

⇒ limited worker skills and supporting infrastructure.

⇒ deregulation and competition defer decisions and increase risk avoidance.

⇒ demonstration of acceptable environmental performance on local coal.


⇒ catalyse economic growth.

⇒ apply joint implementation/activities implemented jointly provisions of the UN FCCC.

⇒ increase the communication of RD&D technology information.

⇒ improve costs, availability and reliability.

⇒ direct government intervention, e.g. financial incentives.

4.4 OECD ASIA/PACIFIC

• Growth in generating capacity in the region until 2015 is projected to be 119 GW of which 24 GW isexpected to be coal-fired capacity (of this 21 GW is expected in Japan).

• The attitude towards clean coal technologies is shaped by the following factors:

⇒ deregulation/competition is becoming a significant factor in capacity choices.

⇒ environmental limitations are important.

⇒ Japan’s capacity choices are driven by the national goal of diversifying the fuel mix to increase thesecurity of supplies.

⇒ return on investment, environmental, politics and capital cost drive capacity decisions.


⇒ deregulation/competition in electricity industry.

⇒ lack of proven availability and financial risk for unit sizes greater than 500 MW in Australia.

⇒ trend toward cost cutting.

• Policies and measures that could over come the barriers are:

⇒ government financial incentives.

⇒ encourage market competition between technologies.

⇒ better methods for disseminating information.

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4.5 NON-OECD ASIA/PACIFIC

4.5.1 Survey of Independent Power Producers

• IPPs remain reluctant to employ clean coal technologies as they judge these technologies to havehigher operating risks and costs.

• Current technology-of-choice appears to be subcritical PF capable of meeting World Bankenvironmental standards.

• Only minor improvements in generating efficiency are expected in the IPP sector before 2000.

• SCPF technology is judged as available, but more costly, with added risks in terms of reliability.

• PFBC and IGCC will be selectively employed where risks are fully covered and incremental costincreases can be recovered.

• Wider market penetration for the emerging clean coal technologies (PFBC and IGCC) is not foreseenuntil the 2005-2010 timeframe or beyond.

• Market penetration of PFBC and IGCC may be accelerated through successfully demonstratingperformance, reliability and costs that are competitive with natural gas-fired, conventional coal andsupercritical PF technologies.

4.5.2 World-Wide Experience with SCPF Technology

• SCPF and advanced SCPF technology are both in wide commercial use throughout the world.

• IPP judgements concerning the performance and costs of SCPF technology are in conflict with actualoperating experience and current capital and operating cost estimates.

• Early problems in 1st and 2nd generation supercritical boilers have been overcome.

• The reliability and availability of SCPF units is comparable to conventional PF units for base loadoperations throughout the life of the unit.

4.5.3 Comparison of SCPF and Conventional PF Performance and Costs

• SCPF and advanced SCPF can achieve significant efficiency improvements over conventionaltechnologies.

• SCPF and advanced SCPF, if installed to meet all or a portion of the projected growth of electricitydemand in the developing countries, can reduce the emissions of CO2 and other pollutants of concernby billions to millions of tonnes over the life of the plants.

• The total capital cost of SCPF and advanced SCPF units is not significantly greater than that of aconventional unit.

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• Advanced SCPF with FGD and SCR can achieve superior emission control levels at a capital cost that

is only 17% ($130/kW) higher than conventional technology with limited pollution control capability.

• SCPF and advanced SCPF have increased generating efficiency and lower generating costs than those

for conventional technology over the broad range of international experience with capital and fuel costs.

• Generating costs for advanced SCPF w/FGD & SCR are lower than conventional technology in the high

fuel cost cases regardless of whether low or high capital costs are assumed, and are only slightly higher

for the low fuel cost cases.

• The economic competitiveness of SCPF is generally applicable, but circumstances of a competitive IPP

market place and lack of local advanced manufacturing facilities in developing regions can render SCPF

non-competitive with conventional coal-fired technologies.

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APPENDICES

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CONTENTS

APPENDIX I - REGIONAL STUDIES ON EVOLUTION OF POWER GENERATION,

OECD NORTH AMERICA............................................................................. 39

I.1. The Potential for Energy Efficient, Coal-Fired Power Generation

in Canada.................................................................................................... 41

I.2. Trends in the Evolution of Energy Efficient, Coal-Fired Power

Generation Technologies in the United States .......................................... 71

APPENDIX II - REGIONAL STUDIES ON EVOLUTION OF POWER GENERATION,

OECD EUROPE .............................................................................................. 87

APPENDIX III - EVOLUTION OF POWER GENERATION, SOUTHERN AFRICA

STUDY ............................................................................................................. 105

APPENDIX IV - OECD ASIA/PACIFIC................................................................................... 123

IV.1. Regional Studies on Evolution of Power Generation, Australia

and New Zealand..................................................................................... 125

IV.2. Study on Evolution of Energy Efficient, Coal-Fired Generating

Technology (Regional Studies Asia-Pacific) .......................................... 155

APPENDIX V -INCREASING THE EFFICIENCY OF COAL-FIRED POWER

GENERATION, STATE OF THE TECHNOLOGY:

REALITY AND PERCEPTIONS................................................................... 161

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APPENDIX I

REGIONAL STUDIES ON EVOLUTION OF POWER GENERATION, OECD NORTH AMERICA

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CIAB / AIE 30/05/00 14:53

I.1

THE POTENTIAL FOR ENERGY EFFICIENTCOAL-FIRED POWER GENERATION

IN CANADA

A Report Prepared for the

COAL INDUSTRY ADVISORY BOARD

Global Climate Committee

Prepared by:Ken Warren, P. Eng,

Director, Genco Technical Services,Edmonton Power

4 September 1996

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CONTENTS

1. EXECUTIVE SUMMARY ............................................................................................... 43

Summary of Responses...................................................................................................... 45

2. INTRODUCTION.............................................................................................................. 46

3. CANADA’S ELECTRICAL SUPPLY SYSTEM............................................................. 46

3.1 The Provincial Systems............................................................................................ 46

3.2 Load Growth ............................................................................................................ 48

3.3 Export and Imports................................................................................................... 49

3.4 Coal-fired Generation............................................................................................... 49

4. GENERATION ADDITIONS SINCE 1980 ..................................................................... 50

5. METHODOLOGY............................................................................................................. 52

6. RESPONSES...................................................................................................................... 53

6.1 Existing and New Capacity ..................................................................................... 53

6.2 Choice of New Capacity: Environmental and Other .............................................. 54

Considerations

6.3 Choice of New Capacity: Technological Considerations ....................................... 57

6.4 Regulation and the Environment ............................................................................. 58

6.5 Coal versus Gas........................................................................................................ 60

7. ADDITIONAL CONSIDERATIONS............................................................................... 61

7.1 Hydroelectric Potential ............................................................................................ 61

7.2 Repowering, Life Extension and Efficiency Enhancement .................................... 61

7.3 Alternative Forms of Generation ............................................................................. 61

7.4 Coal and Gas Prices ................................................................................................. 61

8. DEFINITIONS ................................................................................................................... 62

9. REFERENCES AND ACKNOWLEDGEMENTS........................................................... 62

Figure 1 Electrical Generation by Fuel Type .................................................................. 63

Figure 2 Costs of Fuel for Electricity Generation in Canada ......................................... 63

APPENDIX 1 Questionnaire ..................................................................................................... 64

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1. EXECUTIVE SUMMARY

At the request of the International Energy Agency Secretariat, the Coal Industry Advisory Board, GlobalClimate Committee is soliciting the views of electric power industry expertise within the three OECDregions of the world. This report is a compilation of responses from utilities in Canada which collectivelyrepresent more than 97% of Canada’s coal-fired generation.

Canada is extremely large and therefore a diverse nation in many respects, not least of all in electricitygeneration. Coal availability, quality and cost of extraction vary dramatically from region to region.Natural gas is becoming increasingly available with the development of off-shore resources and anexpanding network of transmission pipelines. Hydraulic energy is abundant in many parts of the countryand nuclear generation has been developed extensively in Eastern Canada. Chapter 3 summarises theregional mosaic of generation type, ownership and regulation.

During the past 16 years (1980-1995, see Chapter 4), new generating capacity has been installed in allparts of the country embracing all “conventional” technologies of hydro, nuclear, gas turbine, internalcombustion and sub-critical steam generation from coal. The only Clean Coal Technology adopted, in thisperiod and before, is atmospheric fluidized bed combustion in Nova Scotia in 1995.

From the survey of provinces a number of statistics emerged:

1. Compared with actual generation capacity in service at the end of 1995, another 2.8% is planned tobe added by 2000 and a further 3.0, 4.3 and 3.4% respectively in each 5-year block until 2015, amodest 0.68% per year. During the same period energy consumption is expected to grow by anaverage 1.38%. [Section 6.1]

2. Of the generation additions, replacements and retrofits planned until 2015, some 15.9% are anticipatedto be coal-fired while 49.8% will rely on natural gas as the primary fuel source. [Section 6.1]

3. In choosing types of new capacity, capital and fuel costs were cited as the top two determining factors,followed by environmental considerations, plant availability, return on capital invested, constructiontime, and security of fuel supply. The high risk of not recovering costs in a deregulated market, andthe reduction of investment risk with shorter planning, design and construction times, are key factors.[Section 6.2]

4. CO2 is considered by many to be the most important environmental factor, followed by SOx and NOxand siting considerations (existing licensing). Some respondents though demonstrated less concernthan others for CO2 as there are no regulations pertaining to this emission at present and damages areless certain than from NOx and SOx. However, in considering their ability to manage these concerns,CO2 was ranked third after NOx and SOx and was considered to be cost prohibitive by one respondent,and another stated that gas is the main CO2 abatement opportunity. [Section 6.2]

5. Of those that predicted some future coal-fired generation additions, replacements or retrofits in theirprovinces, only one gave a firm expectation of using other than pulverised coal, sub-criticaltechnology. This province anticipates adopting IGCC for generation additions after 2005. In another

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province there was some recognition of the possibility of employing any of the Clean CoalTechnologies, subject to their maturity and economic state at the time. In choosing among availableor potential coal-based technologies, capital cost was again ranked as the prime consideration, thisbeing followed by reliability and environmental factors. [Section 6.3]

6. All respondents confirmed that at least one Clean Coal Technology is currently proven and anticipateincreased deregulation over the next 10 years. 7 out of 8 expect that environmental considerations willincrease, environmental costs will impact on coal, and there will be more complex financing in thefuture. 6 expect deregulation to favour gas over coal and 5 respondents opined that long termdecisions are delayed by regulatory uncertainty. There were divided opinions on the availability ofgas, with 2 saying it will become scarce by 2015, 3 saying it will not, 2 anticipating no change inavailability, and 1 “don’t know”. [Section 6.4]

7. When asked what would be needed to overcome barriers to Clean Coal Technology, the majorityresponded with high gas prices. There is also a need for reduced capital costs, increasedcommercially-demonstrated operating flexibility and reliability, and reduced construction periods.Current greenhouse gas strategies are seen as limiting the opportunity for coal development. Taxincentives and financial support for R&D are seen as two ways governments could help. [Section 6.4]

8. Opinions were divided on the ability to improve existing plants. Cost-effective opportunities arethought by some to be limited; others foresee repowering and cogeneration, in one case with gas. Atleast one utility anticipates repowering an existing gas-fired plant to combined cycle operation.Existing regulation puts the capital and environmental costs of such improvements at risk, but onerespondent felt that deregulation will promote Clean Coal Technologies. A change in governmentattitude towards the importance of coal and a clearer regulatory picture are considered essential toovercome these barriers. [Section 6.4]

9. The final question focused on the choice between coal and gas as a plant fuel. The factors mostcommonly selected were: environmental concerns and fuel / generation costs (all 8 respondents);fuel availability and reliability (3); capital costs and risk (2); and construction time, opportunities formore distributed generation (and less transmission) with gas plants, and plant reliability (1 each).One utility anticipates that coal-bed methane might be used for their first coal-based generation.[Section 6.5]

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SUMMARY OF RESPONSES

The following summary for Canada is for inclusion in the Regional Matrix:

Expected load growth in power generation 26.144 (+ 11.087 retrofit)till 2015 (GW capacity)

Rough projection of the split in growth by Coal 5.922, nuclear 0, gas 18.546, hydro 12.193,fuelling type, eg coal, nuclear, gas, hydro oil 0.336, renewable 0.209. Note: These figures

do not exactly match the total expected load growth due to the missing data from 4 provinces and the territories.

Coal capacity (GW) installed since 1980 5.371

Of coal capacity installed since 1980, how AFBC = 0.182. No other CCT.much (GW) is supercritical, how much other advanced coal eg PFBC, IGCC?

Major options other than coal available till Hydro, gas turbines, renewable.2010, eg gas CCT

Are options likely to change after 2010, eg No major changes are anticipated, but possibilitiesforeseen rise in gas prices? are recognised of changes brought about by

environmental and price regulation, and gas availability.

Regional attitudes towards new coal New capacity is likely to be chosen on the basis oftechnology, eg capital cost and financing, capital and fuel costs first, then environmentalregional environmental trends, issues. These factors will tend to favour gasenvironmental acceptability of coal. over coal.

Specific present barriers to installing new Low gas prices, high capital costs and somewhatcoal technology lower commercially-demonstrated reliability and

flexibility.

Ideas for overcoming these barriers Change of government attitude towards the importance of coal, and a clearer regulatory view. Tax incentives; financial support for R&D.

Any other comments? Canadian utilities have been very conservative in adopting new technologies for coal-based generation. Only one unit has ever been built(AFBC) other than sub-critical, pulverised coal units. Concerns for price regulation changes (capital cost recovery) and environmental legislative changes (eg. “carbon tax”) are not likely to encourage comparatively risky decisions.

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2. INTRODUCTION

The International Energy Agency (IEA), in 1979, established the Coal Industry Advisory Board (CIAB) toserve as a mechanism for senior representatives of coal-related enterprises to provide advice andsuggestions to the IEA on coal-related issues. Institutions comprising the CIAB include 15 coal consumerrepresentatives (including electricity generating utilities), 20 coal producers, 8 coal traders, and 2 otherrepresentatives of the transportation and other energy-related enterprises.

The IEA Secretariat has requested the CIAB to provide its perspective on the potential for the electricpower industry to adopt advanced, energy efficient, coal-fired power generation technologies in the nearand medium time frame. Existing studies do not completely answer the questions:

a) What is the outlook for the use of clean coal technologies for electrical generation?;

and

b) What conditions are necessary for the take-up (adoption) of clean coal technologies?

The CIAB Global Climate Committee (GCC) has accepted the responsibility for co-ordinating theresponses on these issues by soliciting the views of electric power industry expertise within the threeOECD regions of the world: North America, Asia/Pacific, and OECD-Europe.

Edmonton Power was requested to respond to the Canadian component of the North America assessment.

3. CANADA’S ELECTRICAL SUPPLY SYSTEM

3.1 THE PROVINCIAL SYSTEMS

There is a mixture of ownership in the electrical supply industry in Canada, ranging from provincial Crowncorporations to investor ownership. For assistance, the following briefly describes on a province-by-province basis how the industry varies. It should be recognised that, although there are many inter-provincial transmission connections, generation, transmission and distribution networks have beenestablished in each province independent of their neighbours.

In most provinces one major, fully integrated electric utility provides all three services, and is frequentlyprovincially owned. In addition there are a large number of smaller -- mostly distribution -- utilities, andsome independent power producers which sell to the major electric utilities. Some cogeneration also existsfor mostly on-site consumption.

With the exception of nuclear power and transmission across international boundaries, regulation is aprovincial responsibility and, except in the case of Alberta as noted below, follows the convention ofprovincial regulator (and perhaps other departmental) approval for new generation and transmission andfor rate setting.

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British Columbia

British Columbia Hydro & Power Authority (BC Hydro) is a Crown corporation which provides electricalservice throughout more than 92%1 of British Columbia, the exception being the southern interior whichis served by investor-owned West Kootenay Power & Light Company, Limited.

Nearly all generation is from hydro stations.

Alberta

Three major utilities provide full electrical service to most of Alberta. Of these, the largest is investor-owned TransAlta Utilities Corporation (about 60%)2, Alberta Power Limited, also investor-owned (about19%), and Edmonton Power Corporation, a subsidiary of EPCOR Utilities Corporation and wholly ownedby the City of Edmonton (about 12%). About 10% of Alberta’s generating capacity is owned byindependent power producers.

More than 90% of provincial generation is from coal.

Effective January 1, 1996, regulation changed to permit the creation of a more competitive environment.From a customer’s perspective there is little if any noticeable immediate change. All existing generationoffers energy to the power pool, as does any supplier including importers, and the pool sells to thedistribution companies at a levelized price. The legislation ensures that these generators will continue tohave their costs shared by all customers in Alberta. However, as load grows and units retire, futuregeneration needs will be met through competition among suppliers (be they existing utilities or IPPs) whowill make financial arrangements with distribution companies or large customers.

Saskatchewan

All electrical service in this province is provided by a Crown corporation, Saskatchewan PowerCorporation (SaskPower).

The majority of generation is coal-fired (about 75%), the remainder being from hydro and natural gas.

Manitoba

The Manitoba Hydro-Electric Board (Manitoba Hydro) supplies the majority of the province’s electricalneeds, with Winnipeg Hydro meeting the balance.

Hydro generation predominates; there is also a small amount of thermal and diesel generation.

Ontario

The majority of the province is supplied either directly, or indirectly by wholesale sales to municipaldistribution utilities, by Ontario Hydro, a Crown corporation. There are also a number of small generationand distribution utilities.

Ontario’s electrical energy is generated mostly from the 82 large stations: 69 hydro, 8 fossil-fired and 5nuclear.

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1. All statistics in this chapter are taken from Electric Power in Canada 1994 and are based on 1994 data.2. Alberta percentages are based on electrical energy supplied in 1994.

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Quebec

Hydro-Québec, a Crown corporation, generates, transmits and distributes most of the province’s electricalenergy.

Hydro-Québec relies mostly on hydro-electric generation, from its 54 stations and from its 34.2% ownershipin the Churchill Falls power plant in Labrador. It also owns 28 conventional thermal stations and 1 nucleargenerating station.

New Brunswick

Publicly-owned New Brunswick Electric Power Corporation (NB Power) supplies the province with energyfrom a mix of thermal, nuclear and hydro power stations.

Nova Scotia

Nova Scotia Power Inc. was established in 1992 following the privatisation of the Nova Scotia PowerCorporation, a Crown corporation.

More than 76% of NSPI’s generation is coal-fired, the remainder being from hydro or oil.

Prince Edward Island

The majority of the island’s electricity is supplied by investor-owned Maritime Electric Company Limitedand is generated by its own oil-fired plants or supplied by NB Power via submarine cables.

Newfoundland

Two large generating and distribution utilities supply Newfoundland & Labrador. The larger generator isNewfoundland and Labrador Hydro but the majority retailer is Newfoundland Light & Power CompanyLimited.

Generation is mainly from hydro but there is also some oil-fired capacity.

The Territories

The Yukon and the Northwest Territories are mostly served by, respectively, the Yukon Electric CompanyLimited and the Northwest Territories Power Corporation.A mix of hydro and internal combustion stations meets most of these requirements.

3.2 LOAD GROWTH

Load growth in Canada from 1989 to 1992 has been well below the global average. During this period it was0.4% (world average = 1.6%).3

48

3. Energy Statistics Yearbook, 1992, pp. 422-470.

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3.3 EXPORTS AND IMPORTS

In 1992, Canada exported 31,528 GWh, 6.1% of its production and imported 6,477 GWh, or 1.3% of itsconsumption of electricity.4

3.4 COAL-FIRED GENERATION

Thermal generation, mainly from coal-fired stations, has been a part of Canada’s generation mix since thebeginning of the electrical power industry. Its share however did not increase significantly until the 1960s,when most of Canada’s economical hydro sites had been developed. The real price of fossil fuels, includingcoal, declined in the period between 1950 and 1974; this encouraged a noticeable increase in the constructionof new thermal plant. From 1960 to 1970 the thermal production share increased from 7% to 23 % andreached a peak of 25% in 1974. With the dramatic increase in oil prices at that time, fossil’s share droppedto 20% by 1985. Since then it rose again slightly (to 23% in 1992), as oil prices collapsed again, but hassince declined, this being attributed to environmental concerns. On a tonnage basis, coal burned increasedover this same time frame from 1.67 million tonne/year in 1960 to 46.4 million tonne/year in 1994.5 In 199481,204 GWh (or 15.2%) of electrical energy was produced from coal, as is illustrated in Figure 1 (page 63).

The distribution of total Canadian coal-fired generation between the provinces in 1994 was as follows 6:

British Columbia 0%

Alberta 52.3%

Saskatchewan 13.8%

Manitoba 0.3%

Ontario 18.3%

Quebec 0%

New Brunswick 6.5%

Nova Scotia 8.8%

Prince Edward Island 0%

Newfoundland 0%

Yukon / Northwest Territories 0%

TOTAL 100%

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4. Energy Statistics Yearbook, 1992, pp. 422-436.5. Electric Power in Canada 1994, pp. 58-64.6. Ibid, p. 64..

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4. GENERATION ADDITIONS SINCE 1980

Year Province Type MW (gross)

1980 Newfoundland Hydro 75Nova Scotia Steam / coal: subcritical 150

Hydro 3.5Wind 0.2

New Brunswick Hydro 100Quebec Hydro 2331Saskatchewan Steam / coal: sub-critical 300Alberta Steam / coal: sub-critical 375British Columbia Hydro 1406NW Territories Internal combustion 2

1981 Quebec Hydro 1680Internal combustion 11

Ontario Gas turbine 42Steam / coal: sub-critical 149

Alberta Steam / coal: sub-critical 375

1982 Nova Scotia Hydro 4New Brunswick Nuclear 680Quebec Hydro 587

Internal combustion 3Ontario Gas turbine 28

Hydro 18Steam / coal: sub-critical 149

1983 Newfoundland Hydro 86Nova Scotia Hydro 3

Steam / coal: sub-critical 159Quebec Hydro 1344

Nuclear 685Internal combustion 2

Ontario Nuclear 540Gas turbine (oil) 70

Saskatchewan Steam / coal: sub-critical 297Alberta Steam / coal: sub-critical 403NW Territories Internal combustion 4

1984 Newfoundland Hydro 5Nova Scotia Hydro 20

Steam / coal: sub-critical 150Quebec Hydro 2179

Internal combustion 2Ontario Nuclear 1816

Gas turbine 34Saskatchewan Gas turbine 42Alberta Steam / coal: sub-critical 394British Columbia Hydro 1383Yukon Hydro 20

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1985 Newfoundland Hydro 127Quebec Hydro 590Ontario Steam / coal: sub-critical 206

Nuclear 1346Saskatchewan Hydro 168British Columbia Hydro 461Yukon Internal combustion 2

1986 Quebec Hydro 885Ontario Nuclear 1346Saskatchewan Hydro 85

Gas turbine (gas) 50

1987 Ontario Nuclear 830Yukon Internal combustion 1NW Territories Internal combustion 3

1988 Newfoundland Steam / oil (uprating) 25Ontario Gas turbine (gas) 52NW Territories Internal combustion 3

1989 Newfoundland Steam / oil (uprating) 25New Brunswick Gas turbine (oil) 25

Steam / oil (uprating) 25Alberta Steam / coal: sub-critical 400Yukon Internal combustion 4NW Territories Internal combustion 4

1990 Quebec Hydro 532Ontario Nuclear 881Manitoba Hydro 384Alberta Steam / coal: sub-critical 383Yukon Internal combustion 4NW Territories Internal combustion 4

1991 Nova Scotia Steam / coal: sub-critical 150Quebec Hydro 1006Manitoba Hydro 532

1992 Quebec Hydro 1201Saskatchewan Steam / coal: sub-critical 300

1993 New Brunswick Steam / coal: sub-critical 443Quebec Hydro 918Ontario Nuclear 1870

Hydro 10Alberta Gas turbine (gas) 34Yukon Internal combustion 1NW Territories Internal combustion 8

1994 Alberta Steam / coal: sub-critical 406Quebec Hydro 1,266Yukon Hydro 0.8

1995 Nova Scotia Steam / coal: atmospheric fluidized bed 182Quebec Hydro 705NW Territories Internal combustion 4

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5. METHODOLOGY

To compile a Canadian perspective on the potential for the electric power industry, a questionnaire wasdeveloped for use by each of the 10 provinces. Where more than one generating utility served a province7,the largest one was asked to answer for the entire province . The Yukon Territory and Northwest Territorieswere not included in the survey due to the relative small size of their systems and low likelihood of anysubstantial coal-fired generation development.

Responses were received from 8 provinces with utilities generating almost 97% of Canada’s electrical loadand 100% of existing coal-fired generation. For the remainder, and for the territories, the most recent CEAdata8 was used where possible. To solicit maximum useful and reliable information for this report, allrecipients of the questionnaire were promised that their responses would be treated in strictest confidence.Therefore the numerical responses have been summated to show the total federal situation, and writtencomments and opinions have been listed with no credits given to their authors.

The questionnaire [Appendix 1] was divided into 6 main topics:

1. Identification of respondent: person, company and province. This information however is not includedin this report.

2. Existing and new capacity: anticipated capacity and energy growth to 2015, capacity retirements,additions and replacements over that same period, and capacity expected to be built in the provincefor export or outside the province for import purposes.

3. Environmental and other, non-technical considerations in the choice of new or replacement capacity.

4. Technological options being considered for new or replacement generation capacity.

5. Opinions in the province on matters relating to regulation, financing, the environment, and fuel andtechnology choices, including barriers to be overcome, and the roles that governments and regulatorsshould play.

6. Opinions on the factors likely to determine the choice of coal or gas as the fuel in future plants.

52

7. In the case of Alberta, Edmonton Power’s staff compiled the response based on best available information and opinion. Since theintroduction of a competitive regulatory framework on January 1, 1996 the concept of cooperative generation planning has all butdisappeared. No one utility is willing to reveal to its competitors what plans it has for capital additions or retirements any more than isrequired by the regulation of existing plant. An attempt has been made though to embrace what is known of utilities’ positions based ongeneration planning that took place until last year and informal discussions between parties.

8. Electric Power in Canada 1994

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6. RESPONSES

The following tables contain a summation of data from the survey respondents or, in its absence, most recentCEA data available.9

It should be noted that the totals in Tables 2.3 and 2.4 should not be compared with those in Tables 2.1 and2.2. Tables 2.3 and 2.4 were compiled entirely from responses from the six provinces, whereas Tables 2.1 and2.2 used survey data where provided and CEA data for the rest of Canada.

6.1 EXISTING AND NEW CAPACITY

Table 2.1Forecasts of maximum installed electric capacity and annual use of electricity

Generation Actual Capital additions

1995 1996-2000 2001- 2005 2006-2010 2011-2015

Capacity (MW) 107,667 3,052 3,277 4,622 3,639

Energy (GWh) 486,716 27,731 30,205 33,526 43,166

Note: All capacity figures on a net basis.

Table 2.2Anticipated retirements of existing generating capacity

Capacity retirements 1996-2000 2001-2005 2006-2010 2011-2015

Capacity to be retired (MW) 513 746 3,560 6,598

Table 2.3Anticipated capacity additions

Capital additions (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Coal 0 117 1,150 2,000Nuclear 0 0 0 0Hydro 1,118 1,828 4,585 2,960Natural gas 1,137 647 2,366 3,448Oil 0 143 0 193Dual-fired coal/oil* 0 0 0 0Dual-fired gas /oil* 0 0 0 0Orimulsion 0 0 0 0Renewable resources 0 110 62 25

TOTAL 2,255 2,845 8,163 8,626

* Note: Dual-fired means full capacity to use either fuel.

The numbers in Table 2.3 give only an indication of the installed capacity.

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9. Electric Power in Canada 1994.

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Table 2.4Expectations for source of replacement capacity (including retrofit in brackets)

Capital replacements & Retrofits* (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Coal 0 0 105 (1,300) 0 (1,250)Nuclear 0 0 0 0

Hydro 900 (40) 237 525 0

Natural gas 1,023 (313) 724 (734) 354 (3,300) 350 (4,150)

Oil 0 0 0 0

Dual-fired coal/oil 0 0 0 0

Dual-fired gas/oil 0 0 0 0

Orimulsion 0 0 0 0

Renewable resources 0 0 37 0

TOTAL 1,923 (353) 961 (734) 1,021 (4,600) 350 (5400)

* Note: Retrofit can be assumed to mean exchange of more-or-less technologically similar parts, including those key elements used forlife extension purposes.

Further to capital additions, replacements and retrofits included in Tables 2.3 and 2.4, respondents wereasked to forecast extra generating capacity primarily to serve export loads

Table 2.5: No capacity was forecast by any utility.

They were also asked to forecast generating capacity that would be constructed outside of the provinceprimarily for importing electricity into the province [Table 2.6]. Again the response was zero.

6.2 CHOICE OF NEW CAPACITY: ENVIRONMENTAL AND OTHER CONSIDERATIONS

Table 3.1Which factors are considered important for the forecasted choice of new capacity

in Tables 2.3, 2.4 and 2.5 within the time frame until 2015, ranked 1-10, with 10 being the most important and 1 being the least important factor

Determining factor Rank

Access to indigenous fuel (coal, gas) 2Fuel flexibility 3Security of fuel supply 4 Capital cost 10Fuel cost 9Requests for rate of return on investment 6Building time 5Overall reliable plant technology (eg. availability) 7Environmental considerations 8Political considerations 1

The above ranking is a composite of the rankings received.

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Table 3.2Breakdown of environmental considerations (ranked from 1 - 6, with 6 being the most important),

based on two considerations: the importance of the environmental factors and the ability to manage these factors

Environmental factor Importance ManageabilityRanking Ranking

Carbon dioxide (CO2) 6 4

Sulphur oxides (SOx) 5 5

Nitrogen oxides (NOx) 4 6

Trace elements* 2 1

Siting considerations (eg. existing licensing) 3 3

Others: 1 2

* Trace elements include those of environmental concern such as As, Ba, Be, B, Cd, Cl, Co, Cu, F, Hg, Mn, Mo, Ni, Pb, Se and Zn.

The above ranking is a composite of rankings received.

For the highest rankings in Tables 3.1 and 3.2, the following responses describe the reasons for theimportance of the specific factors:

Determining factor (Table 3.1):

• Cost competitiveness of generation (ie. economics) is still the primary factor in selecting generatingoptions.

• Cost - new investments must be competitive with market prices.

• Fuel cost is the most important operating cost, determining marginal cost and hence competitivestance.

• In a deregulated marketplace, the owner will face high risks when adding new capital plant withoutguarantees of recovering the costs.

• It is very important to reduce the length of the time between the planning decision to build a newpower station and its commissioning. This [would] enhance the decision environment for long-termgeneration planning by reducing uncertainty in demand evolution and reducing the economic risk ofbuilding the station too soon.

• Minimising risk and lowest economic cost are key. Fuel cost and capital cost are the most significantfactors needing control. Building time and reliability contribute to effective utilisation of the facilityand, therefore, cost of product. ROI is a function of the above.

• Providing electrical services at the lowest cost is [our company’s] highest priority.

• The capital cost of new capacity plays a significant role in identifying the choice of new capacity.Since [our utility] aims to determine the least cost option for supplying future power and energy, thecapital cost of future generation additions impacts on the cost effectiveness of meeting future loadgrowth. Also, capital cost of new capacity impacts on the corporation’s rate structure. This must beevaluated, especially the near term impacts.

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Environmental factor ranking (Table 3.2):

• CO2 emissions are the most global in their visibility and impact, and the least able to be managed.

• Currently, generation is limited in order by NOx, CO2 and SO2. Siting could influence timerequirement and cost of implementation. Trace elements and others [factors] do not appear limitingat present.

• Greenhouse gas will be a major factor in the development of any new thermal resource.

• International commitments place this [CO2] issue above all other environmental needs.Limited opportunities for a coal burning utility to reduce emissions. Gas is our best opportunity forshort term reduction.

• Maximum ground level concentrations of SO2 are regulated by provincial legislation. Control of groundlevel concentrations of SO2 at existing thermal generation sources has been found to be complicated byvariable terrain and particularly meteorological conditions at coastal locations. As well, the SO2emissions from new thermal generation must be considered in relation to an agreement between the[provincial government] and [the utility] which places a limit on the weight of SO2 which may be emittedby [the utility’s] facilities in a calendar year.

• NOx and SOx, which cause identifiable local damages, are considered more important than CO2 forwhich the damages are much more uncertain.

• Of the environmental factors, siting factors and SO2 and NOx are the most important because of existingregulatory requirements or guidelines. While CO2 and trace elements are of concern, there are noregulations at this time.

• Reducing emissions causing acid rain will remain an objective in the province. Thus NOx and SOxemissions will remain very important issues.

Environmental factor manageability (Table 3.2):

• CO2 emissions are the least able to be managed (reduced significantly).

• Greenhouse gas mitigation strategies. NOx can be limited by SCRs. It is very hard to reduce CO2emissions. It is relatively easy to reduce NOx formation during combustion and further reduction is stillpossible by trapping it before emission from the stack. By using fuel with less sulphur it is also relativelyeasy to reduce SOx emissions.

• Many technologies available for SO2 / NOx control, eg. CFR, FGD, etc. Gas is the main CO2 abatementopportunity when available.

• Siting and emission control for NOx and SOx are much more manageable than CO2 emissions.

• SO2 and NOx control problems are widely available and proven. Siting considerations and othersgenerally can be [managed] inexpensively. Trace elements: control of some is well demonstrated;[control of] others such as mercury is more difficult and costly. CO2: limited technology fixes. Fuel choice,market credit trading and offsets have significant potential.

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• The technology for capture and disposal of CO2 is limited and very expensive. As well, the quantity ofCO2 emitted by thermal generation facilities on [the utility’s] system in any year is significantlyinfluenced by water levels in reservoirs at our hydroelectric facilities. Whenever possible, generationfrom hydroelectric facilities is maximised.

• There are existing procedures and technologies for dealing with siting, SO2 and NOx. Cost effectivemanagement of CO2 and trace elements is considered to be cost prohibitive at this time.

6.3 CHOICE OF NEW CAPACITY: TECHNOLOGICAL CONSIDERATIONS

Table 4.1Expectations for the technological split in new coal-based electricity capacity

(with retrofit in brackets) 10

Generation type (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Sub-critical 0 117 400 0Supercritical 0 0 * 0Ultra-supercritical 0 0 * 0AFBC 0 0 * 0PFBC 0 0 * 0PFBC CC 0 0 * 0IGCC 0 0 * and 750 2,000

* 400 MW of new generation capacity (listed as sub-critical) may use any of these technologies depending on their maturity andeconomics.

Table 4.2The most important factors for your expectations for choice of technology as described

in Question 4.1, ranked from 1-9 for each of new capacity and retrofitted capacity

Determining factors New capacity Retrofit capacityranking ranking

Capital cost 9 9

Rate of return on investment 7 4

Overall reliable plant technology 8 7

Environmental considerations 7 8

Time to construct 5 3

Regulatory environment 4 7

Operating and maintenance costs 4 2

Market requirements 2 7(baseload, intermediate or peaking duty)

Greenfield vs. Brownfield 1 1(excluding environmental considerations)

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10. The technology definitions are included in Chapter 8.

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6.4 REGULATION AND THE ENVIRONMENT

Table 5.1Respondents’ opinions

Statement Yes No No change Don’t know

Deregulation will increase for the next 10 years 8 0 0 0

Long term decisions are “put on hold” due 5 2 1 0to uncertainty concerning deregulation.

More complex financing is expected 6 0 1 1

Environmental considerations will increase 7 1 0 0

Nuclear energy will increase in Canada 0 3 1 4

Deregulation will favour gas over coal 6 1 0 1

One or more Clean Coal Technologies 8 0 0 0are satisfactorily proven11

Coal will be burdened with environmental costs 7 0 0 1

Gas will become scarce before 2015 2 3 2 1

Numbers indicate number of responses in each category.

Respondents’ opinions on what would have to happen to help overcome any barriers and accelerate theadoption of Clean Coal Technologies:

• Good proven performance of commercial scale units in utility environment: environment / reliability/ operability / cost of power.

• Increased gas prices relative to coal (3 or 4 : 1). Reduced clean coal technology costs (US$1100/kW). Increased operating flexibility. Reduced construction time and cost.

• Increase of natural gas prices.

• Lower capital and operating and maintenance costs required to compete with oil-fired technology.

• Natural gas prices would need to rise sufficiently to make Clean Coal Technologies competitive.

• Price of natural gas would have to increase; availability drop.

Respondents’ opinions on the role that government policies and/or international co-operation could play inencouraging the efficient use of coal and/or the adoption of Clean Coal Technologies:

• At this time clean coal technology is not cost competitive with conventional coal technology. To helpfurther develop clean coal technology, governments must provide support for research anddevelopment.

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11. One respondent added that Clean Coal Technologies are not competitive at actual and forecasted natural gas prices.

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• Canadian government policy which caters to Eastern Canadian interests will not be a factor in WesternCanada. No policy could encourage the use of coal.

• Favourable tax/depreciation for environmentally sound technologies requiring penetration assistance.

• Funding a substantial portion of up-front R&D and demonstrations consistent with long termenvironmental policies.

• Greenhouse gas strategies appear to limit the opportunity for coal development.

• Increase taxes on natural gas uses.

Respondents’ opinions on what technical opportunities exist for improving existing plants:

• Life management matched with role. Modifications to major systems experiencing mid-life failures -blading enhancements; expert systems; new controls. Consideration of life extension / repowering -steam turbine repowering and windbox repowering. Increased operating factors through external sales.

• Not applicable as our system is mainly hydroelectric.

• Repowering and cogeneration.

• Repowering is being considered [at an existing gas-fired plant].

• Repowering with gas (when available).

• There are limited opportunities for improving heat rates due to the inherent design of existing plants.There are opportunities to incrementally improve heat rates in various areas throughout the plants, butthese in many cases will be offset by additional environmental controls being imposed on existing plants.

• Thermal life extension plans have not identified any cost effective opportunities to increase plantefficiencies.

Respondents’ opinions on what are the regulatory disincentives for making these improvements:

• Costs associated with improvements beyond present regulatory requirements not allowed in rate base.


• The major disincentive is the possibility of major future environmental costs directed against coal basedgeneration.

• There are none. Deregulation will promote these.

• Tight emission control requirements have required the addition of SCR [to some existing gas-firedunits]. All units will be fitted if repowering does not proceed.

• Uncertain marketplace mechanisms and resulting role.

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Respondents’ opinions on what would have to happen to help overcome these disincentives:

• A change in attitude as to the future role and importance of coal.

• A rationalisation of federal / provincial government department goals. Clarification of future marketplace rules re. stranded assets, new capital investments, pricingmechanisms, strategies, and elements.

• No real disincentives.


6.5 COAL VERSUS GAS

Respondents’ opinions on which are the most important factors in determining the choice between coal andnatural gas for fuelling power plants:

• Availability beyond 2000 ±. Relative cost of generation. Environmental restraints forcing newgeneration / technology additions, or repowering, with gas.

• Availability of fuel. Reliability of supply. Capital costs. Fuel costs. Environmental factors.

• Differential fuel price. Environmental constraints. Capital cost differential and risk. Constructionperiod. Financing resulting from above. Potential for more distributed generation and reduced newtransmission.

• Gas is favoured by: (1) lower emissions; (2) Lower greenhouse gas contributions; (3) lower cost; and(4) infrastructure in place. First use of coal for [our utility] might be recovery of coal-bed methane.

• 1: Cost / 2: Environmental impacts.

• 1: Cost / 2: Reliability (unit availability) / 3: Environmental concerns.

• The factors which are likely to impact coal the most are the potential and proposed environmentalregulations directed against coal based generation.

• The factors which are the most important vis-à-vis natural gas are its future availability and price.

• The most important factors in determining the choice between coal and natural gas are environmentalimpact and total generation cost. Coal will be considered for fuelling power plants in this provincewhen, considering all equipment required to reduce environmental impacts to levels comparable tothose of electrical generation using natural gas, the total generation costs are competitive.

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7. ADDITIONAL CONSIDERATIONS

7.1 HYDROELECTRIC POTENTIAL

In 1992 Energy, Mines and Resources Canada12 listed the remaining potential hydro development inCanada based on their own data and information supplied by utilities.

In total 185,833 MW gross potential was identified (excluding sites already developed or underconstruction). Of these, only 43,886 MW was considered to be candidates for future development afterrecognising technical, economic and environmental restraints.

7.2 REPOWERING, LIFE EXTENSION AND EFFICIENCY ENHANCEMENT

As will be noted from the responses in Table 2.3 [see Section 6.1], at least 10,120 MW of retrofitting isanticipated in the next 20 years, such as the addition of a gas turbine to an existing steam turbine unit tocreate a combined cycle plant. In addition, many utilities plan to use life extension techniques to extendunits’ lives beyond original design.

The value of heat rate (or efficiency) improvements has recently increased beyond the hard economics ofreduced fuel costs or increased generation revenue. As a means of also reducing CO2 emissions per kWhgenerated, utilities are considering many efficiency-enhancing modifications such as improved LP rotorlast stage blading.

7.3 ALTERNATIVE FORMS OF GENERATION

Although this study has been limited to consideration of a limited number of Clean Coal Technologies, itis recognised that many others probably exist on an extended horizon to the 20 years of this review.

They include technologies such as fuel cells, magneto hydrodynamics (MHD), the Kalina cycle,combustion of municipal solid waste and wood, solar and wind energy and (perhaps one day) nuclearfusion.

7.4 COAL AND GAS PRICES

As can be seen from Figure 2, gas costs have decreased since 1983 while coal costs have changed verylittle. This historical trend tends to support gas as a fuel of choice.13

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12. Electric Power in Canada, pp. 139-149.13. Electric Power in Canada, 1994, pp. 110-114. Note: These costs have been calculated from Electric Power Statistics, Statistics Canada,

catalogue 57-202, Various issues and reflect the cost of generation in Nova Scotia, New Brunswick and Ontario (Eastern coal) andAlberta, Saskatchewan and Manitoba (Western coal).

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8. DEFINITIONS

Clean Coal Technologies include all of the following:

Sub-critical: Power generation in which pulverised coal is burned in a boiler at atmospheric pressure,the steam produced being at all points below a pressure of 22.12 MPa, the steam being used to drivea steam turbine.

Supercritical: Power generation in which pulverised coal is burned in a boiler at atmospheric pressure,the steam produced being at some point above a pressure of 22.12 MPa, but which is not classed asultra-supercritical.

Ultra-supercritical: Supercritical plant which has a maximum steam temperature above 566 C or amaximum steam pressure above 24.8 MPa.

AFBC: Atmospheric Fluidized Bed Combustion: Plant in which coal is burned in a fluidized bed, eitherbubbling or circulating, at atmospheric pressure, with heat being recovered to power a steam turbine.

PFBC: Pressurised Fluidized Bed Combustion: Plant in which coal is burned in a fluidized bed atpressure, with heat being recovered to power a steam turbine.

PFBC CC: Pressurised Fluidized Bed Combustion Combined Cycle: Plant in which coal is burned in afluidized bed at pressure, with the flue gas being passed through a gas turbine and the waste heatbeing used to raise steam.

IGCC: Integrated Gasification Combined Cycle: Plant in which coal is converted to fuel gas which is thenburned in a gas turbine, the hot exhaust from which is used to generate steam for a steam cycle.

9. REFERENCES AND ACKNOWLEDGEMENTS

Recognition should be given to the following, who assisted in the preparation of this report:

Andy Keller and Doug Heaton of EPCOR, Edmonton Power.

Dermot Lane of Fording Coal Limited.

All respondents to the questionnaire, The Evolution of Coal-Fired Power Generation in North America,which was used to compile much of this report.

Data from the following documents was also used in this report, as referenced in footnotes:

Electric Power in Canada 1991, published by the Electricity branch, Energy Sector of Energy, Mines andResources Canada.

Electric Power in Canada 1994, published by the Canadian Electricity Association and the EnergyResources Branch, Energy Sector of Natural Resources Canada.

Energy Statistics Yearbook, 1992, published by the United Nations.

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Figure 1

Electrical Generation by Fuel Type

Figure 2

Costs of Fuel for Electricity Generation in Canada

1983 1984 1985 1986

Natural gas Eastern coal Western coal

1987 1988 1989 1990 1991 1992 1963

40

35

30

25

20

15

10

5

0

$/M

Wh

Nuclear19.1%

Oil1.1%

Hydro60.9%

Other0.8%

Coal15.2%

Natural gas2.9%

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APPENDIX 1

THE EVOLUTION OF ENERGY EFFICIENTCOAL-FIRED POWER GENERATION

IN NORTH AMERICA

1.0 IDENTIFICATION OF RESPONDENT

1.1 Name of company and person responding to the questionnaire:

1.2 Province in which the utility is located:

2.0 EXISTING AND NEW CAPACITY

2.1 Based on expectations for the whole province, please indicate your forecast for maximuminstalled electric capacity and annual use of electricity:

Table 2.1

Provincial Actual Capital additions

Generation 1995 1996-2000 2001- 2005 2006-2010 2011-2015

Capacity (MW)

Energy (GWh)

* Note: All capacity figures should be on a net basis.

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2.2 Please indicate anticipated retirements of existing generating capacity:

Table 2.2

Capacity retirements 1996-2000 2001-2005 2006-2010 2011-2015

Capacity to be retired (MW)

To meet the requirements for installation of additional and replacement capacity, the following illustrationmay assist:

Table 2.3

Capital additions (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Coal

Nuclear

Hydro

Natural gas

Oil

Dual-fired coal/oil*

Dual-fired gas /oil*

Orimulsion

Renewable resources

TOTAL

* Note: Dual-fired means full capacity to use either fuel.

Table 2.5

Table 2.3

Table 2.4

Year

Retirements (Table 2.2)

M

W

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2.4 The numbers in Table 2.3 give only an indication of the installed capacity. It is verylikely though that new capacity needs to be built to replace old capacity. Thereforeplease indicate in Table 2.4 your expectations for source of replacement capacityincluding retrofit.

Please state retrofit share in brackets.

Table 2.4

Capital replacements & retrofits* (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Coal

Nuclear

Hydro

Natural gas

Oil

Dual-fired coal/oil

Dual-fired gas/oil

Orimulsion

Renewable resources

TOTAL

*Note: Retrofit can be assumed to mean exchange of more-or-less technologically similar parts, including those key elements used for

life extension purposes.

2.5 Further to capital additions, replacements and retrofits included in Tables 2.3 and 2.4, pleaseindicate if you anticipate building extra generating capacity primarily to serve export loads.

Table 2.5

Capacity for export (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Coal

Nuclear

Hydro

Gas

Oil

Dual-fired coal/oil

Dual-fired gas/oil

Orimulsion

Renewable resources

TOTAL

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2.6 Please indicate any anticipated generating capacity that would be constructed outside of yourprovince primarily for import of electricity into your province:

Table 2.6

Capacity for import (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Coal

Nuclear

Hydro

Natural gas

Oil

Dual-fired coal/oil

Dual-fired gas/oil

Orimulsion

Renewable resources

TOTAL

3.0 CHOICE OF NEW CAPACITY: ENVIRONMENTAL AND OTHER CONSIDERATIONS

3.1 Which factors are important for your expectation to the forecast of choice of new capacity inQuestions 2.3, 2.4 and 2.5 within the time frame until 2015? Rank each factor with a number 1- 10, with 10 being the most important and 1 being the least important factor:

Table 3.1

Determining factor Rank

Access to indigenous fuel (coal, gas)

Fuel flexibility

Security of fuel supply

Capital cost

Fuel cost

Requests for rate of return on investment

Building time

Overall reliable plant technology (eg. availability)

Environmental considerations

Political considerations

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3.2 Please break down environmental considerations and rank from 1 - 6 (6 being the most important)and based on two considerations: the importance of the environmental factors; and the ability tomanage these factors:

Table 3.2

Environmental factor Importance Ranking Manageability Ranking

Carbon dioxide (CO2)

Sulphur oxides (SOx)

Nitrogen oxides (NOx)

Trace elements*

Siting considerations (eg. existing licensing)

Others:

* Trace elements include those of environmental concern such as As, Ba, Be, B, Cd, Cl, Co, Cu, F, Hg, Mn, Mo, Ni, Pb, Se and Zn.

3.3 For the highest rankings in each of Tables 3.1 and 3.2 please describe in a few words your reasonfor the importance of the specific factors:

Determining factor:

Environmental factor importance:

Environmental factor manageability:

If your expectations are in favour of non-coal-fired capacity, based on the capacity indications inQuestions 2.3, 2.4 and 2.5, skip directly to Question 5.1.

4.0 CHOICE OF NEW CAPACITY - TECHNOLOGICAL CONSIDERATIONS

4.1 Please indicate your expectations for the technological split in your province’s new coal-basedelectric capacity. (Refer to Tables 2.3, 2.4 and 2.5.) Please state retrofit in brackets:

Table 4.1

Generation type (MW) 1996-2000 2001-2005 2006-2010 2011-2015

Sub-critical

Supercritical

Ultra-supercritical

AFBC

PFBC

PFBC CC

IGCC

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Definitions

Note: Clean Coal Technologies include all of the following:

Sub-critical : Power generation in which pulverised coal is burned in a boiler at atmospheric pressure, thesteam produced being at all points below a pressure of 22.12 MPa, the steam being used to drive a steamturbine.

Supercritical : Power generation in which pulverised coal is burned in a boiler at atmospheric pressure,the steam produced being at some point above a pressure of 22.12 MPa, but which is not classed as ultra-supercritical.

Ultra-supercritical Supercritical plant which has a maximum steam temperature above 566C or amaximum steam pressure above 24.8 Mpa.

AFBC : Atmospheric Fluidized Bed Combustion: Plant in which coal is burned in a fluidized bed, eitherbubbling or circulating, at atmospheric pressure, with heat being recovered to power a steam turbine.

PFBC : Pressurised Fluidized Bed Combustion: Plant in which coal is burned in a fluidized bed atpressure, with heat being recovered to power a steam turbine.

PFBC CC : Pressurised Fluidized Bed Combustion Combined Cycle: Plant in which coal is burned in afluidized bed at pressure, with the flue gas being passed through a gas turbine and the waste heat beingused to raise steam.

IGCC : Integrated Gasification Combined Cycle: Plant in which coal is converted to fuel gas which is thenburned in a gas turbine, the hot exhaust from which is used to generate steam for a steam cycle.

4.2 What are the most important factors for your expectations for choice of technology as describedin Question 4.1? Rank from 1-9 for each of new capacity and retrofitted capacity:

Table 4.2

Determining factors New capacity Retrofit capacityRanking Ranking

Capital cost

Rate of return on investment

Overall reliable plant technology


Time to construct

Regulatory environment

Operating and maintenance costs

Market requirements (baseload, intermediate or peaking duty)

Greenfield vs. Brownfield (excluding

environmental considerations)

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5.0 REGULATION AND THE ENVIRONMENT

5.1 Please provide your opinions on the statements presented below:

Table 5.1

Statement Yes No No change Don’t know

Deregulation will increase for the next 10 years

Long term decisions are “put on hold” due to uncertainty concerning deregulation.

More complex financing is expected

Environmental considerations will increase

Nuclear energy will increase in Canada

Deregulation will favour gas over coal

One or more Clean Coal Technologies are satisfactorily proven

Coal will be burdened with environmental costs

Gas will become scarce before 2015

5.2 What, in your opinion, would have to happen to help overcome any barriers and accelerate theadoption of Clean Coal Technologies?:

5.3 What sort of role could government policies and/or international co-operation play inencouraging the efficient use of coal and/or the adoption of Clean Coal Technologies?:

5.4 What technical opportunities exist for improving your province’s existing plants (by improvedheat rate, increased output, etc.)?:

5.5 What are the regulatory disincentives for making these improvements?:

5.6 What, in your opinion, would have to happen to help overcome these disincentives?:

6.0 COAL VERSUS GAS

6.1 In your opinion, which are the most important factors in determining the choice between coal andnatural gas in your province for fuelling power plants?:

Thank you for taking your time to respond to this questionnaire.

Note: All responses to this questionnaire will be treated in strictest confidence. Opinions and otheranswers will be included in the summary report, but in a manner not to reveal their source.

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I.2

TRENDS IN THE EVOLUTION OF ENERGYEFFICIENT COAL-FIRED POWER GENERATION TECHNOLOGIES

IN THE UNITED STATES

Prepared for:


Global Climate Committee

Prepared by:Peabody Holding Company, Inc.

St. Louis, Missouri USA

September 10, 1996

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CONTENTS

1. INTRODUCTION.............................................................................................................. 73

2. GROWTH IN ELECTRICITY DEMAND....................................................................... 73

3. GENERATING CAPACITY ADDITIONS ...................................................................... 74

4. POTENTIAL FOR THE INSTALLATION OF ADVANCED, ENERGY EFFICIENT, COAL-FIRED POWER GENERATION TECHNOLOGY............................................. 75

4.1 Description ............................................................................................................... 75

4.2 Capital Cost Comparison......................................................................................... 75

4.3 Environmental Considerations................................................................................. 76

4.4 Potential for Installation........................................................................................... 77

5. BARRIERS TO THE INSTALLATION OF ADVANCED, ENERGY EFFICIENT, COAL- FIRED POWER GENERATION TECHNOLOGY............................................ 77

6. ROLE OF GOVERNMENT POLICIES AND MEASURES IN THE INSTALLATION OF ADVANCED, ENERGY EFFICIENT, COAL- FIRED POWER GENERATION TECHNOLOGY ......................................... 79

Appendix 1 Clean Coal Technology Coalition Utility Survey....................................... 81

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1. INTRODUCTION

The Coal Industry Advisory Board to the IEA has been asked by the IEA Secretariat to provide an assessmentof regional attitudes towards the up-take of advanced energy efficient coal-fired technologies. The assessmentis to address the issues of regional load growth, capacity additions by fuel type, attitudes toward the advancedtechnologies described in previous OECD/IEA reports prepared by the CIAB, barriers to the up-take of theadvanced technologies and policies and measures that might be adopted by governments and others toovercome the barriers. The following is the assessment for the United States.

2. GROWTH IN ELECTRICITY DEMAND

During the period 1995 through 2015 electricity sales in the United States are projected to increase by 31%(EIA, 1996). Total kilowatt hour sales will increase from 2,973 billion to 3,899 billion by 2015. Theresidential use of electricity will lead this increase with growth of 39% during this period, see Table 2.1.Commercial and Industrial electricity sales will grow at the lower rates of 27% and 24% respectively.

Table 2.1United States Electricity Sales, 1995 - 2015 (Billion Kilowatt Hours)

ChangeYear 1995 2000 2005 2010 2015 1995 - 2015

Residential 1,024 1,084 1,172 1,282 1,419 39%

Commercial 939 984 1,039 1,105 1,189 27%

Industrial 1,004 1,059 1,131 1,184 1,240 24%

Transportation 6 9 20 32 40 600%

TOTAL 2,973 3,137 3,363 3,604 3,889 31%

Generation by fuel type shows a shift from coal and nuclear generation to natural gas, see Table 2.2 (EIA,1996). The EIA has assumed that when nuclear units reach their 40th year of operation they will be retiredand taken out of service. A significant amount of nuclear unit retirement occurs after 2010. If this does notoccur and the life of nuclear units are extended, the increases in coal and gas generation will be smaller. Theincrease in petroleum (61%) and natural gas (129%) generation is projected to result from the installation ofsimple and combined cycle combustion turbines.

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Table 2.2United States Electricity Generation By Fuel Type, 1995 - 2015

(Billion Kilowatt Hours)

ChangeYear 1995 2000 2005 2010 2015 1995 - 2015

Coal 1,710 1,841 1,977 2,071 2,146 25%

Petroleum 74 71 100 124 119 61%

Natural Gas 503 518 620 783 1,153 129%

Nuclear 658 664 649 610 434 (34%)

Other 403 421 434 449 490 22%

TOTAL 3,348 3,515 3,780 4,037 4,342 30%

3. GENERATING CAPACITY ADDITIONS

Installed generating capacity in the US will have to increase by 22% to meet the projected increase inelectricity sales between 1995 and 2015 (EIA, 1996). The greatest increase in generating capacity is projectedto occur in the non-utility and co-generation sectors as opposed to the tradition electric utility sector, seeTable 3.1. Cumulative additions total 252 thousand megawatts. Forty percent of the new capacity is installedbetween 2010 and 2015. During this period, 84 thousand megawatts of capacity will be retired from theelectric utility sector. A significant portion of the retirements is associated with nuclear units being taken outof service after 2010.

Table 3.1 United States Electric Generating Capacity Additions, 1995 - 2015(Thousand Megawatts)

ChangeYear 1995 2000 2005 2010 2015 1995 - 2015

CapabilityElectric Utility 705 720 741 757 765 9%

Non-Utility 19 35 41 67 115 490%

Co-generation 46 50 53 55 58 27%

TOTAL 770 804 834 879 937 22%

Cumulative AdditionsElectric Utility 7 41 70 97 143 –

Non-Utility/Co-generation 2 21 31 59 110 –

TOTAL 9 62 101 156 252 –

Cumulative Utility Retirements 2 21 30 44 84 –

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The change in capacity addition projections by fuel type shows the preference for natural gas over coal duringthe period 1995 through to 2015, see Table 3.2 (EIA,1996). Coal-fired generation is projected to increase by5% or 15,500 megawatts, while natural gas and oil-fired generating capacity is expected to increase by 69%or 165,800 megawatts. Again, the majority of the new capacity is projected to be installed after 2010 andwhen nuclear capacity appears to be replaced with natural gas-fired capacity.

Table 3.2United States Electric Generating Capacity Additions

By Fuel Type, 1995 - 2015 (Thousand Megawatts)

ChangeYear 1995 2000 2005 2010 2015 1995 - 2015

Coal 314 310 315 323 329 5%

Natural Gas/Oil 241 273 296 336 407 69%

Nuclear 99 100 100 93 64 (36%)

Other 116 121 123 126 138 19%

TOTAL 770 804 834 879 937 22%

The electricity industry in the United States is currently in the early stages of moving from a regulated to aderegulated structure. The traditional utility structure where electricity suppliers had the sole franchise tosupply power to all customers in a service territory, guaranteed rates of return on capital investments and theability to pass through to the customer fuel price adjustments is giving way to open access for all parties toall customers. The impacts of total deregulation are not known at this time. However, one can anticipate thatthe greater risk of an open market will cause the generator of electricity to become more price competitive,cost conscious and less willing to make large capital outlays for new generating capacity and especially forcapacity that may be in the early stages of its commercial acceptance.

4. POTENTIAL FOR INSTALLATION OF ADVANCED, ENERGYEFFICIENT, COAL-FIRED POWER GENERATION TECHNOLOGY

4.1 DESCRIPTION

In order to access the potential for the installation of advanced, energy efficient, coal-fired powergeneration technology, three advanced technologies have been selected for consideration here. They aresupercritical pulverised fuel combustion (Supercritical PF), pressurised fluidized bed combustion (PFBC)and integrated gasification combined cycle (IGCC). These advanced technologies have been described indetail in various technical literature. (OECD/IEA, 1994; OECD/IEA, 1995; OECD/IEA, 1996)

4.2 CAPITAL COST COMPARISON

Capital cost estimates for installing the technologies have also been included in the technical literature.The following Table 4.2 summarises selected operating and cost parameters for the three technologies and

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is compared to conventional subcritical pulverised fuel technology (Subcritical PF) (OECD/IEA, 1996). Itis important to note that since the data included in these published estimates were gathered, capital costsfor the conventional pulverised coal technology has been reported to have been reduced by more than 30%(EUW, 1996). These capital cost reductions have resulted from improved standardised design techniques,reduction in major component costs, improved construction methods and increased competition amongmanufacturers. It is highly likely that these same cost reductions would be carried over into the installationof the advanced technologies, but the extent of the carry-over is not known.

Table 4.2Comparison of Selected Technologies

State of Unit Size Net Efficiency Capital CostTechnology Technology MWe % US $/KW

Subcritical PF Fully Commercial 50-1000 36-38 950-1300

Supercritical PF Commercial 50-1000 40-46 950-1600

PFBC Commercial 70-350 42-45 1000-1500

IGCC Just Commercial 100-320 43-45 1500-1600

4.3 ENVIRONMENTAL CONSIDERATIONS

The advanced energy efficient, coal-fired power generation technologies have been proven to have a higherlevel of environmental performance as it relates to the conventional air emissions from combustion (SOx,NOx and particulate matter) and to the emission of carbon dioxide. For example, a state-of-the-art coal-fired power plant will be more efficient than a conventional coal-fired power plant (42% HHV versus 36%HHV) and, as a result, emit 13% less CO2 per year. (Torrens, 1996) Environmental performance isbecoming an ever more important consideration as US environmental standards become more stringentand the potential for regulating carbon emissions is under review. Energy related carbon emissions in theUS are projected to increase to 1,735 million metric tons by 2015 (EIA, 1996; EPA, 1995). This representsan increase of 30% over 1990 levels. These projections do not factor in any efforts to control greenhousegas (GHG) emissions that may result from the US being a party to the UN Framework Convention onClimate Change (FCCC). The FCCC requires nations to return to their 1990 GHG emission level by 2000.

Table 4.3United States Carbon Emissions from Energy Consumption, 1990 - 2015

(Million metric Tons)

ChangeYear 1990 1995 2000 2005 2010 2015 1990 - 2015

Coal 482 499 524 555 573 591 21%Natural Gas 274 312 327 353 381 421 53%

Petroleum 580 602 638 677 705 721 24%

Other 0 0 0 1 2 2 –

TOTAL 1,336 1,413 1,490 1,585 1,660 1,735 30%

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4.4 POTENTIAL FOR INSTALLATION

The potential for the installation of the advanced, energy efficient, coal-fired power generation technologiesis directly related to the amount of new electric generating capacity that will be built between now and 2015.As identified in Section 3, the amount of new capacity is projected to be 252,000 megawatts. It is alsoimportant to note that the need for 150,000 megawatts of this new capacity occurs during and after 2005.The advanced technologies are at the very early stages of commercial acceptance and another 8 to 13 yearsof development will allow them sufficient time to reach their full commercial potential.

However, the potential for the installation of the advanced technologies will, in all likelihood, be reducedby the impacts of utility deregulation on power generators and the low cost of installing natural gas-firedcombined cycle technology. The potential will be further reduced if restrictions are placed on fossil fuelcombustion as result of concerns over global climate change.

5. BARRIERS TO THE INSTALLATION OF ADVANCED, ENERGYEFFICIENT, COAL-FIRED POWER GENERATION TECHNOLOGY

A major determinant for the potential of installing the advanced technologies is the attitude that the electricpower generation industry has toward the technologies. Two efforts have been conducted to access theindustry’s attitude; one by the Clean Coal Technology Coalition (CCTC, 1994) and another by the USDepartment of Energy (DOE, 1996).

In February, 1994 the Clean Coal Technology Coalition (CCTC) distributed a survey to the members ofthe Association of Edison Illuminating Companies Power Generation Committee. The survey was notdistributed to independent power producers, municipal power systems or industrial generators. The CCTCreceived responses to the survey from companies with a combined capacity of over 200,000 megawatts, orabout 31% of the installed capacity of the United States. The objective of the survey was “to obtain dataconcerning opportunities, perceptions and requirements for deploying Clean Coal Technologies”. Theresults of the survey are attached as Appendix 1. The CCTC survey identified a number of barriers to theinstallation of advanced technologies.

Key findings of the survey are:

• There is limited opportunity for the installation of base load plants > 100 MWe before 2000.

• Opportunities for base-load plants >100 MWe increase for the period 2000 - 2005.

• Non-utility generators will play an increasingly important role in meeting new capacity additions.

• IGCC, PFBC and Supercritical PF are perceived to be more expensive than Subcritical PF.

• IGCC, Supercritical PF and PFBC are viewed as having higher maintenance costs than Subcritical PF.

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• Subcritical PF and Supercritical PF are proven/reliable technologies while IGCC is somewhatproven/reliable and PFBC is not proven/reliable.

• Subcritical PF still appears to be the technology of choice, but the negative perception of the advancedtechnologies does not reflect current operating experience or cost projections.

• Altering the utility regulatory structure alone would not encourage the adoption of advancedtechnologies, but a program enacted to reduce risk by reducing costs would be an importantencouragement for installing the advanced technologies.

Based on the survey results the CCTC made the following recommendations:

1. A better job should be done to market the advanced technologies by providing more information on risksand costs.

2. Non-utility generators need to be targeted.

3. Without cost sharing to reduce risk the advanced technologies are unlikely to be installed in the 2000 -2005 timeframe.

In 1992 the US Department of Energy, Fossil Energy Department (DOE/FE) began a series of interviews todetermine what it will take for corporate officials/key decision makers to give serious consideration to theinstallation of clean coal technologies and other advanced power generation technologies in their futurecapacity addition plans (DOE, 1996). The DOE/FE is looking for feedback in the following areas:

• level of awareness of the clean coal technology program.

• impact of utility deregulation.

• assessment of risk and risk mitigation for the installation of advanced technologies.

• government incentives that could accelerate the commercial acceptance of advanced technologies.

As of January 1996, the interviews had involved the senior management of: investor owned and municipalutilities (27), independent power producers (10), state regulatory agencies (5), financial institutions (2),equipment manufactures (1) and insurance carriers (2). DOE/FE has plans to contact environmental groups,international organisations and other key stakeholders. The organisations that were interviewed weresubjected to a screening criteria that qualified them as having coal-fired generating capacity, a need forcapacity in the future, regulatory authority over capacity installations or the ability to supply advancedtechnologies.

DOE/FE made a number of observations and findings as a result of the interviews. The following are someof those which are related to the potential markets for clean coal technologies:

• deregulation is delaying indefinitely long-term decisions for additional generating capacity.

• new baseload capacity is not required until the next decade.

• considerable interest exists for IGCC but less interest in PFBC.

• strong interests exists for life-extension and improving performance of existing plants. Many utilities arefocusing on investments in developing countries where demand for new capacity is high.

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The interviews also identified a number of barriers to the installation of advanced technologies and DOE/FEcharacterised those barriers as follows:

• coal continues to have a bad reputation, but many executives still prefer it as the fuel-of-choice forbaseload.

• natural gas will continue as the fuel-of-choice for incremental capacity additions in the near term.

• advanced coal-fired technologies will face tough competition due to high initial capital costs relative togas-fired technologies.

• concern exists over future regulation of CO2.

• life-cycle costing is less important than in past - decisions are being driven by short-term considerations.

• in the absence of incentives, developing countries focus on short-term costs and lack environmentaldrivers that would favour installation of advanced coal-fired technologies.

6. ROLE OF GOVERNMENT POLICIES AND MEASURES IN THE INSTALLATION OF ADVANCED, ENERGY EFFICIENT,

COAL-FIRED POWER GENERATION TECHNOLOGY

The potential for the installation of advanced, energy efficient, coal-fired power generation technology appearsto be greater in the longer term, beyond 2005. However, wide commercial acceptance is contingent on theoutcome of the deregulation of the electricity industry in the US and power generating companies’ attitudestoward risk and efforts to mitigate risk associated with advanced technologies. The costs and benefits ofadvanced technologies must be equal or greater than those for conventional technologies. In addition, life-cyclecosts will need to continue to be an important factor in the selection of future capacity additions.

If the US Government or any other government were inclined to encourage the further commercialisation ofthe advanced technologies they would need to provide some manner of financial incentive that addresses theincreased risk of installing and operating an advanced technology. A number of alternatives for policies theUS Government could adopt have been suggested. Most of the alternatives focus on mechanisms that wouldeither lower the initial capital costs of the advanced technology or provide a monetary incentive that wouldlower its life-cycle costs. Two alternatives that have been solicited, but not endorsed, by the US DOE arediscussed below.

An analysis of incentives to accelerate the commercial of “first of a kind clean” coal technologies (South, 1995)identified that tax and permitting incentives could make power generators indifferent to the selection of anadvanced technology versus a conventional technology. Foregoing tax revenue at the beginning of theinstallation was judged in the analysis to be the most effective, least cost method to improve the economics ofthe advanced technology. Four tax incentives and two combinations were investigated in the analysis. Theseincluded: 5 and 10 year tax lives, 10% investment tax credit and a $1.50/MWh production tax credit. Theanalysis projected that developing the advanced technologies to commercial maturity would, over the life of aninstallation, more than cover the tax losses and the benefits to the US Treasury from the mature technologycould be 400% greater than for a comparable natural gas-fired combined cycle technology. Permittingincentives were projected to have a minimal impact on life-cycle costs, but were judged to be an importantelement to reduce delays which in turn will reduce costs.

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Another approach that has been examined is for the US Government to implement an incentive program thatwould result in levelized electricity price parity between first-of-a-kind clean coal technologies and naturalgas-fired combined cycle generation. The advanced technologies examined were PFBC and IGCC and theincentives were to be graduated, highest for the first installations, for 5 PFBC and 5 IGCC installations. Inthe beginning the price incentive may have to be as high as 1.62 cents/kwh but would be reduced as thetechnologies become commercially mature. The total incentive amount would be $3.2 billion dollars net oftaxes collected from these first 10 advanced installations. The incentive would be guaranteed for the first 20years of operation of the facility. The incentive program would result in the commercial maturity of these 2advanced technologies by 2010.

The applicability of either of these mechanisms outside the US would have to be examined on aregional/county basis. In addition, the practicality of these approaches in a totally deregulated utility industryin the US or another country would also have to be considered.

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APPENDIX 1

CLEAN COAL TECHNOLOGY COALITION1050 Thomas Jefferson Street, N.W. Seventh Floor, Washington, D.C. 20007

Chairman: (202) 342-3368 Executive Director

Dr. James R. Markowsky Facsimile Ben Yamagata

Executive Vice President (202) 338-2361

Amerrican Electric Power Service Corp. (202) 338-2416

April 4, 1994

The Honorable Hazel O’Leary Secretary The Department of Energy Washington, D.C. 20585

Dear Madam Secretary:

The Clean Coal Technology Coalition would like to present to you the results of ourutility industry survey, which sought to measure industry’s interest and confidence in the costand reliability of clean coal technologies, given their current state of development. A copy of the analysis of the survey data is attached. The Coalition represents a broad range oforganizations interested in the continued demonstration and commercialization of clean coaltechnologies (a membership list is included).

On January 21, 1994, the survey was sent to members of the Association of EdisonIlluminating Companies Power Generation Committee. The Committee is comprised oftwenty-five representatives of major U.S. utilities that promote technological advances in thepower generation field by providing a forum for dialogue between manufacturers and users toexchange industry needs and technology developments. Dr. James R. Markowsky, ExecutiveVice President, American Electric Power Service Corporation, is a member of the PowerGeneration Committee and is currently the Chairman of the Clean Coal Technology Coalition.

I hope you find the survey results of interest. Of particular importance, the respondents to the survey represent nearly one-third of the total U.S. installed electric capacity. Of those utilities responding, over 50% indicated a lack of confidence in thereliability of clean coal technologies as currently demonstrated, and none of the utilities found clean coal technologies such as atmospheric fluidized bed, pressurized fluidized bed,and integrated gasification combined cycle, to be cost effective at this time. However, 61 % of the respondents indicated an interest in pursuing the further commercialization of clean coal technologies if a commercialization program, similar to that proposed by the Coalition,were implemented.

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We believe this survey may respond to your call for industry to demonstrate utilityinterest in the future application of clean coal technologies and the need for continuation of the DOE’s clean coal program (made while addressing the National Coal Council onNovember 19, 1993). Dr. Markowsky and I would welcome the opportunity to fully brief you on the results of our survey and answer any questions you may have concerning theircontent and the Coalition’s recommendation for a clean coal commercialization program.

Please do not hesitate to contact me at (202) 298-1857 if I can provide you withadditional information on the Clean Coal Technology Coalition or the Coalition’s survey. Thank you for your consideration and I look forward to hearing from you.

Respectfully

Ben YamagataExecutive Director

Enclosures

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CLEAN COAL TECHNOLOGY COALITIONUTILITY SURVEY

In February, 1994, a survey was distributed to executives of utility members in the AEIC Power GenerationCommittee. The objective of this survey was to obtain data concerning opportunities, perceptions, andrequirements for deploying Clean Coal Technologies.

Eighteen of the twenty-five utilities who were sent surveys responded, representing in excess of 200,000MW, or about 31% of the installed capacity of the United States. It is important to note that the survey wasaimed at only one segment of the market. Independent Power Producers, Municipal Power Systems, andindustrial users were not included in the survey.

The results of the survey are as follows:

I. NEW DOMESTIC CAPACITY ADDITIONS

Questions were asked about the projected capacity additions for the time periods 1995 to 2000, and 2000 to2005. An analysis of the responses indicated the following trends:

1995 - 2000

There are limited opportunities for base-load plant > 100 MW in the 1995 to 2000 time frame. Projectionswere:

• 22% projected new base-load plants < 100 MW

• 22% projected repowerings < 100 MW

• 6% projected new base-load plants 100 to 500 MW

• 11% projected repowerings 100 to 500 MW

• There were no projections for base-load or repowering units > 500 MW

• 62% of respondents project using purchased power

• 72% of respondents project using peaking power

The project fuel for peaking capacity additions is natural gas, however, coal represents the projected fuel fora majority of the base load plants.

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2000-2005

The opportunities for base-load plants > 100 MW increase in the 2000 - 2005 time frame.Projections were:

• 6% projected new base-load plants < 100 MW

• 17% projected repowerings < 100 MW

• 39% projected new base-load plants 100 to 500 MW

• 11% projected repowerings 100 to 500 MW

• 44% projected new base-load plants > 500 MW

• No one projected repowerings > 500 MW

• 55% of respondents project using purchased power

• 67% of respondents project using peaking power

The projected use of coal increases in this time frame, which is consistent with the greater projections fornew base-load capacity additions.

It is noteworthy that over 50% of the respondents projected purchasing power to meet their capacity additionsin both time frames.

Conclusions which can be gleaned from the above data are:

1. The greatest market for new and repowered plants in the utility sector before the year 2000 is in the< 100 MW range.

2. The market for plants > 100 MW in the utility sector is very limited before the year 2000.

3. The market potential for plants > 100 MW in the utility sector increases after the year 2000.

4. Non Utility Generators will be important players in meeting new capacity additions.

II. PERCEIVED TECHNOLOGY CHARACTERISTICS

The survey provided a menu of perceived characteristics for the following technologies:

Subcritical PC, Supercritical PC, AFBC, PFBC, IGCC, Wet FGD, Dry FGD, and SCR

The characteristics that the respondents were requested to check as they believed to pertain to eachtechnology were:

A) High Capital Cost, B) High Maintenance Cost, C) Cost Effective, D) Proven Technology, E) Unproven/Unreliable, F) High Efficiency, G) Reduced Emissions, and H) Flexible

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The most often checked perceived characteristic for each of the given technologies are given in Table 1.

Table 1.Most often checked perceived characteristics for each technology

Subcritical PC: Proven Technology

AFBC: Reduced Emissions

Supercritical PC: Proven Technology

PFBC: Unreliable/Unproven Technology

IGCC: High Capital Cost; Reduced Emissions

Wet FGD: Reduced Emissions

Dry FGD: Reduced Emissions

SCR: High Capital Cost

The order of ranking of the generating technologies for each characteristic are given in Table 2.

Table 2.Order of ranking for each characteristic for generating technologies

A) High Capital Cost IGCC, (Sup PC, PFBC), AFBC, Sub PC

B) High Maintenance Cost IGCC, AFBC, (Sup PC, PFBC), Sub PC

C) Cost Effective (Sub PC, Sup PC), (AFBC, PFBC, IGCC)

D) Proven Technology Sub PC, Sup PC, AFBC, IGCC, PFBC

E) Unproven/Unreliable PFBC, IGCC, AFBC, Sup PC, Sub PC

F) High Efficiency Sup PC, IGCC, PFBC, Sub PC, AFBC

G) Reduced Emissions IGCC, AFBC, PFBC, Sub PC, Sup PC

H) Flexible (IGCC, AFBC), (PFBC, Sub PC), Sup PC

Notes: • Ranking is from greatest to least percentage.• Parenthesis means an equal percentage.• Technologies which were checked by more then 50% are single underlined.• Technologies which were not checked at all are double underlined.

Conclusions which may be gleaned from the above data are:

1. CCT generation technologies (AFBC, PFBC, and IGCC) are perceived to be expensive.

2. CCT generation technologies (AFBC, PFBC, and IGCC) are not perceived to be cost effective.

3. CCT generation technologies (AFBC, PFBC, and IGCC) are perceived to be unproven/unreliable.

4. Subcritical PC’s still appear to be the technology of choice for utilities.

5. Many of the negative perceptions concerning CCT’s do not reflect current operating experience andcost projections for the technologies.

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86

III. COST SHARING AND INCENTIVES

The respondents were asked the following questions:

1. “If the existing regulatory structure were altered to allow utilities to more readily adopt clean coal

technologies, would you seriously consider using one of these technologies to meet your capacity

needs?”

33% of the respondents checked “yes”, while 67% checked “no, altering the regulatory structure

alone will not sufficiently address all my concerns”

2. “If a program could be enacted that would reduce the risk by reducing the cost for utilities that adopt

(in a commercial setting) a clean coal technology, would you participate in such a program?”

61% of the respondents checked “yes”, and 22% checked “no”

Conclusions which can be gleaned from the above data are:

1. Addressing regulatory issues alone (eg. passing higher costs on to the customers) would not suffice to

encourage deployment of CCT’s.

2. Providing cost-sharing incentives (eg. making CCT’s cost indifferent during early deployment) is

important to encourage deployment of CCT’s.

IV. RECOMMENDATIONS

Based on the above results, the following recommendations were made by the Clean Coal Technology

Coalition:

1. CCT advocates should do a better job in addressing the prevailing perceptions by better marketing of

the merits of CCT’s.

• There is a need to disseminate successes in the demonstration plants to address real and perceived

risks.

• There is a need to publish more definitive information about the projected costs of CCT’s.

2. Non Utility Generators need to be targeted for involvement in CCT’s.

3. The survey results should be provided to DOE and policy makers to demonstrate that cost-sharing

incentives are essential to allow deployment of CCT’s in the 2000 to 2005 time frame. Without cost

sharing to make CCT’s cost indifferent during their early deployment, it is unlikely that they will

be the technology of choice in the 2000 to 2005 time frame.

CIAB / AIE 30/05/00 14:53

II

REGIONAL STUDIES ON EVOLUTION OF POWER GENERATION

OECD EUROPE

INTERNATIONAL ENERGY AGENCY


Climate Change Committee

ReportRegional Studies on Evolution of Power Peneration

OECD/EUROPE

September 1, 1996

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CONTENTS

1. INTRODUCTION.............................................................................................................. 89

2. EXECUTIVE SUMMARY ............................................................................................... 90

3. LOAD GROWTH .............................................................................................................. 91

4. ENERGY GENERATION FUEL APPORTIONMENT .................................................. 92

5. THE DETERMINANT FACTORS IN CHOICE OF NEW CAPACITY ....................... 94

6. NEW COAL BASED CAPACITY - TECHNOLOGY/ATTITUDES............................. 96

7. BARRIERS TO THE TAKE UP OF CLEAN COAL TECHNOLOGY......................... 97

AND WAYS TO OVERCOMING THEM

8. OPINION ON VARIOUS ENERGY RELATED ISSUES .............................................. 99

9. APPENDICES

1. Completed questionnaire ............................................................................................... 100

2. Recipients of the questionnaire...................................................................................... 104

This report has been prepared by SK Power Company, Copenhagen on behalf of the Coal IndustryAdvisory Board (CIAB) of the International Energy Agency (IEA)

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1. INTRODUCTION

Background

The International Energy Agency (IEA) secretariat has requested the Coal Industry Advisory Board (CIAB)to provide its perspective on the potential for the electricity power industry to take up advanced, energyefficient, coal fired power generation technologies in the near and medium term time frame.

The report should estimate the expected load growth and corresponding fuel choices for the period up to year2015, as well as define the determining factors for these fuel choices.

Furthermore, the report should describe the planned take up of Clean Coal Technology (CCT), as well as theindustry view on the barriers to enhanced take up of CCT and the ways to overcome those barriers.

The CIAB Global Climate Committee was made responsible for co-ordinating the responses by soliciting theviews of the electricity power industry within three OECD regions of the world, namely North America,Asia/Pacific and Europe.

This report covers the findings pertaining to OECD-Europe.

Methodology

The view of the European electricity power companies was sought by means of a questionnaire (appendix 1)which was sent to representative companies in all the European OECD countries. Where the country hadassigned a member to the CIAB, the questionnaire was directed to the company of that member.

Appendix 2 lists all the recipients of the questionnaire.

When the completed questionnaires were returned, most of those who had replied were then interviewed bytelephone. A planned visit/interview with the representatives of the utilities from the 5 major countries inEurope had to be given up due to the European holiday season, which made arranging appointments virtuallyimpossible.

Questionnaires were sent out in early July 1996 with 1st August as the original deadline for replies. Thedeadline was later extended by a month.

Time frame

The questionnaire sought industry opinions on the expected developments for the coming 20 year period.Whereas most respondents actually did venture into the unknown, most of them put strong question marksas to the reliability of these expectations, especially for the period after year 2005. With respect to the 2010-2015 timeframe, only countries representing some 70% of the total electric capacity amongst the respondentswere willing to give their opinion. For this reason, that last 5-year period has therefore not been included inthe study.

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Response Rate

The questionnaire was circulated to 16 European countries. Austria, Belgium, Denmark, Finland, France,Germany, Greece, Ireland, Italy, Netherlands, Norway, Spain and UK responded before the (revised)deadline.

Portugal, Sweden and Switzerland either did not respond or responded too late for inclusion in the report.

For the purpose of this report, the phrase “OECD-Europe” includes only the 13 countries that provided input.


The electricity industry in OECD Europe expects a fairly constant load growth over the period from 1995-2010, of the order of some 16% in capacity and a higher 27% in energy use.

As a consequence of the on-going transition of the industry from one of monopolies to a deregulatedcompetitive market, power companies have redefined their earlier strategic/politically based objectives(technological reliability/availability, fuel flexibility and use of indigenous fuels) to economic ones like returnon investment and capital cost. At the same time, environmental considerations are expected to continue toplay an important role in future choice of generating capacity.

European power companies expect oil to lose ground as an input energy source in Europe over the next 15years, while coal and nuclear should be stable and hydropower see a small increase. Capacity based onrenewable fuels will enjoy a large increase (but even then still remain an incremental energy producer).

Gas will be the big growth winner

Gas has relatively low capital costs and an environmentally friendly image. Indeed, it is remarkable that, evenif most European power companies state that “Europe is becoming too dependant on imported gas”, they stillplan to opt for precisely that fuel for new capacity.

In comparison with gas, expectations for new coal-based capacity is low. What is built over the coming 10years will primarily be Supercritical PF, one of the 4 Clean Coal Technologies (CCT) that are the subject ofthis study. After year 2005, the choice of new coal based capacity will depend on the state of the individualtechnology at that time.

The main barriers for the enhanced take up of Clean Coal Technology are economic in nature (high capitalcosts) and, except for those countries already hosting CCT’s, a sceptical attitude as to the maturity of thesetechnologies. Furthermore coal has a public/political image problem.

To overcome these barriers various proposal have been brought forward by the power companies:

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• With respect to the higher capital costs, suggestions include the political support for the continueddevelopment and dissemination of CCT’s through subsidies, financing or funding, and the preferentialtreatment in the marketplace of CCT output.

• When it comes to overcoming the scepticism about the maturity of CCT technologies, the fact thatcountries hosting CCT’s have a strong confidence in their virtues could indicate that a betterdissemination of information on the demonstration plants could constitute an effective way of provingthe abilities of the CCT’s.

• Finally, environmental barriers (including public and political image problems) could be overcome bymore information on the virtues of coal as a fuel, i.e. the large and geographically widespread resourcebase and the technologically advanced state of coal mining and usage today. Furthermore, theimplementation of closed handling systems at harbours and powerplants might help.

3. LOAD GROWTH

Electricity generating capacity in OECD-Europe is projected to continue to grow through the period 1995 to2010. This assumption is based on input from the European utilities participating in this study.

Figure 1Energy and Capacity in OECD Europe

All respondents are expecting increases both in energy use and in installed capacity, regardless of all theinitiatives on energy saving, Least Cost Planning or Integrated Resource Planning. As can be seen, the growthexpectations for the period 1995-2010 are quite high, with some 16% growth in capacity and a higher 27%growth in energy use.

600.0

Capacity

EnergyEne

rgy

in 1

0**4

GW

hC

apac

ity in

100

0 M

W

500.0

400.0

300.0

200.0

100.0

0.01995 2000

Years

2005 2010

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The greater expected increase in energy use compared to total capacity means that the production facilitiesare expected to be more intensively utilised in the future, with peak and spare capacity reduced.

4. ENERGY GENERATION FUEL APPORTIONMENT

The question on the split between energy sources is supposed to give an indication of which fuels areexpected to be used in European power production for the period to 2010 (2015). The details can be foundin the tables in Appendix 1.

Figure 2Development in Total Capacity

Reviewing these figures leads to a few general observations:

• for nuclear power, the fairly constant picture covers the new capacity being brought on line in Franceconcurrently with the closing of ageing capacity;

• for hydro power, a 7% growth in capacity is expected, with a fairly constant growth factor and fairlywell spread geographically over approximately half of the responding countries. The hydro power plantsare probably not producing their maximum output due to climatic variations;

Cap

acity

in M

W

140000

120000

100000

80000

60000

40000

20000

0

1995

2005-2009

Dua

l Coa

l/Oil

+

Coa

l

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l Gas

/Oil

+

Oil

Nuc

lear

Hyd

ro Oil

Ren

ewab

le +

Impo

rt

Oth

er

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• for oil-based capacity, a quarter of current capacity is expected to close within the next 15 years andforecasted new oil capacity is relatively small;

• renewables, (waste, wind, biomass and solar) could more than double by the year 2010, but even thenwould represent only some 5-6 % of the combined total of gas and coal capacity.

It is therefore expected that new generating capacity will primarily be gas or coal fired.

Examining the anticipated developments in coal and gas based capacity (figure 3), it is apparent that thelack of growth for other fuels is more than outweighed by the very sharp increase in gas fired capacity. Itshould also be noted that the additional gas capacity is not expected to be based on dual-fuel technology,but rather on capacity fuelled only by gas.

Figure 3:Total capacity forecast in OECD Europe split between coal and gas at energy source

Sharp increase in gas fired capacity for power production.

1995

1996

-199

9

2000

-200

4

2005

-200

9

Cap

acity

in M

W

120000

100000

80000

60000

40000

20000

years

Coal Dual Coal/Oil Gas Dual Gas/Oil

0

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5. THE DETERMINANT FACTORS IN CHOICE OF NEW CAPACITY

Judging from the responses received, de-regulation and it’s consequences is already present in the minds and

the planning of European utility executives.

In figure 4, the first column indicates the average response from all countries regardless of the country’s size,

whereas the second column displays a weighted average based on each country’s total installed capacity.

Determining factors were ranked from “1” to “10”, with “1” indicating the least important factor and “10”

the most important.

Figure 4

Determining factors in the choice of new technology

Determining Factor

A: Access to indigenous fuel (coal, gas) F: Requests for rate of return on investment

B: Fuel Flexibility G: Building time

C: Security of fuel supply H: Overall reliable plant technology (eg. availability)

D: Capital cost I: Environmental considerations

E: Fuel cost J: Political considerations

0

1

2

3

4

5

6

7

8

9

A B C

Determining Factors

Distribution Data AV Weighted Distribution Data W

D E F G H I J

Impo

rtanc

e

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“The choice of new capacity will be driven primarily by rate of return criteria in a commercial environment where competition is increasing”

With the development (in some countries actual - in some expected) of a competitive market, utilities haveredefined their priorities in generation choices, having upgraded considerations connected to economically-driven objectives like return on investment, fuel and capital costs, and down-graded some of the more stra-tegic objectives of the former power-monopolies like reliability/availability of the production capacity, fuelflexibility and the use of indigenous fuels.

The high consideration given to environmental issues that is envisaged in the utility sector is a sign of theanticipated continuation (but this time more indirect) of authority influence on the development of the powergeneration sector, in combination with the growing importance of international and regional public opinion.

When asked to detail the most important environmental considerations in the choice of technology, there isa tendency for Europe to break into two, with Southern Europe seeing the abatement of sulphuroxides andnitrogenoxides as the major challenge and Northern European countries expressing the opinion thatcarbondioxide has taken the lead as the number one problem. Trace elements were mentioned a couple oftimes as one of the coming considerations.

With the lesser importance put on the older virtues, as mentioned above, and their replacement by more short-term considerations, in combination with a continued strong emphasis on environmental issues, the way ispaved for gas-turbines and combined cycle technologies.

Figure 5New Capacity in OECD Europe

Energy source split for new installed capacity

Coal

25000

20000

15000

10000

5000

1995 1996-1999

Years

2000-2004 2005-2009

0

Dual Coal/Oil

Gas

Dual Gas/OilCap

acity

in M

W

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The main worry expressed by several utilities in making the apparently easy choice of gas-based technologyhas to do with the geographical location of gas resources, coupled with the apparent insatiable appetite forgas in large areas of the world.

One example mentioned is the potential increase in demand for Russian gas not only in that country itself,but also in the Far East (China, Korea, Japan), Turkey and Eastern and Central European countries. Theanxiety is linked to considerations of security of supply and price developments.

“Natural gas has many advantages in the short term.Pricing/availability may swing demand back to coal, if environmental issues permit”

6. NEW COAL BASED CAPACITY - TECHNOLOGY/ATTITUDES

For the purpose of investigating expectations with regard to the type of new coal technology, thequestionnaire contained a question encompassing four Clean Coal Technologies (CCT) and oneconventional technology (Sub Critical Pulverised Fuel).

Figure 6New Coal Based Technology Split

96

Cap

acity

in M

W

8000

7000

6000

5000

4000

3000

2000

1000

0

Development in new coal based capacity-technology split

Year1995 1996-1999 2000-2004 2005-2009

Sub-Critical Super-Critical AFBC

PFBC IGCC

CIAB / AIE 30/05/00 14:53

The CCT’s were Supercritical Pulverised Fuel (Supercritical PF), Atmospheric Fluidized Bed Combustion(AFBC), Pressurised Fluidized Bed Combustion (PFBC) and Integrated Gasification Combined Cycle(IGCC) - these technologies have previously been described in the report “Factors affecting the take-up ofClean Coal Technologies” CIAB/IEA 1996.

For the next 10 years, the main development in new coal-based capacity is expected to be Supercritical PF,followed by conventional Subcritical PF and, to a much lesser degree, the three remaining CCT’s. It isgenerally thought that Supercritical PF is a proven and reliable technology, whereas the remaining CCT’sstill need some time to gain general acceptance. The choice of technology after 2005 is still very open,with most respondents stating that, with the current state of technology, Supercritical PF would be chosen,but that major advances in further developing other CCT’s may well alter this in the future.

CCT’s are generally chosen due to their superior electric efficiency. However, where Combined Heat andPower is generated, the total efficiency even for conventional Subcritical PF becomes very high and thistechnology is considered satisfactory in some regions with district heating systems.

“Clean Coal Technology should have environmental effects not too far from burning Natural Gas and should be cheap”

7. BARRIERS TO THE TAKE UP OF CLEAN COAL TECHNOLOGYAND WAYS TO OVERCOMING THEM

In the developing market conditions, where environmental performance and shorter term economicrequirements are the main criteria of success, Clean Coal Technology is required to be able to competewith natural gas.

• Environmentally coal has a public (and political) image problem and some utilities further fear thatcoal will be hit harder by energy and environmental (CO2) taxation than natural gas.

• With regard to economic competitiveness, the main drawback for CCT is it’s higher capital costcompared to gas technology.

• Finally there still exists some uncertainty as to which/whether CCT’s have reached the point ofproven, reliable technology. In countries which already host CCT’s, the confidence in thattechnology and the expectation of its growth potential is generally good, whereas countries withoutCCT’s are more sceptical.

The suggestions that have been put forward in the returned questionnaires to overcome the barriers to thetake up of Clean Coal Technology can be categorised as follows:

Capital cost : Capital cost should be reduced. This could be achieved by political support in financing,direct funding/subsidies or contributions to the continued development of CCT technologies, to make themmore affordable.

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It is also proposed that the effects of the higher capital cost could be neutralised by political interventionin the marketplace (e.g. by subsidising CCT output or by reserving part of the market solely for CCT).

Environmental performance : Actions proposed to reduce barriers to CCT take up include theharmonisation of energy taxation and emission limits and the removal of the threat of carbon taxation.

As regards the public and political opinion on coal, it should be worked on by more information about thevirtues of coal as a fuel, i.e. the large and geographically wellspread resource base and the advancedtechnological state of coal mining and coal usage today. Also the implementation of closed handlingsystems at harbours and powerplants would probably help.

Maturity of the Technology : Countries hosting CCT’s have a greater confidence in them (Supercriticalin Germany and Denmark, and IGCC, to some extent, in the Netherlands and Spain), whereas countrieswithout the technologies are sceptical. Several respondents suggest that politicians should make themeans available to develop more pilot projects and demonstration plants, to further develop thetechnology, as a domestic reference plant seems to be an effective way of proving the reliability of theCCT in question.

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8. OPINION ON VARIOUS ENERGY RELATED ISSUES

The questionnaire asked respondents to reply to a series of statements related to energy issues. Answerscould be “yes”, “no”, “00” meaning “no change” or “??” meaning “do not know”.

Figure 7

Table totalling attitudes to a number of statements

Statement All Countries

Yes No 00 ??

A Deregulation will increase for the next 10 years 14

B Long term decisions put “on hold” 12 1 1

C More complex financing is expected 10 3 1

D Environmental considerations will increase 14

E Nuclear energy will increase in OECD Europe 8 3 3

F Liberalisation will favour gas for coal 13 1

G One or more CCT’s are satisfactorily proven 6 2 1 5

H Coal will be burdened with environmental costs 10 1 2 1

I Europe is becoming too dependant on imported coal 4 5 2 3

J Local storage of gas will be imposed 5 2 7

K Gas will become scarce before 2015 2 8 2 2

L Europe will become too dependant on imported gas 8 2 1 3

The numbers represent the number of countries having made the various replies, and one can say that theresults are self-explanatory and illustrate very clearly the messages given in the other parts of this report.

It could be worthwhile to point out that, regardless of the fact that a majority of respondents find that“Europe will become too dependant on imported gas”, gas is still expected to be chosen by the those samecompanies and will become the big growth winner under the newly created competitive market conditions.

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APPENDIX 1

FILLED OUT QUESTIONNAIRE. NUMBERS ARE TOTALS FROM THE RECEIVED REPLIES.

THE EVOLUTION OF ENERGY EFFICIENT COAL-FIRED POWER GENERATION IN OECD-EUROPE

1. Name of company and person responding to the questionnaire:

2. Based on expectations for the whole country (e.g. not only Rheinland-Phalz in Germany but thewhole Federal Republic of Germany or Scotland also as part of UK) please indicate your forecast formaximum of installed electric capacity and annual use of electric energy:

Table 1

1995 2000 2005 2010 2015

Capacity in MW 487932 516311 537266 563931Energy in GWh 2113371 2322558 2490785 2682594

3. Based on the total installed capacity in your country, please indicate how the capacity is expected tobe split between various energy sources:

Table 2

1995 1996-1999 2000-2004 2005-2009 2010-2015

Coal 103033 102502 98366 100168

Nuclear 105150 110790 110790 104770

Hydro 117318 120567 122553 124937

Gas 45589 60598 78223 95929

Oil 52219 45359 43074 46392

Dualfired- Coal/oil 26490 29044 29225 30296

Dualfired Gas/oil 21942 30236 30620 30619

Orimulsion 1328 0 2053 2283

Renew. 4217 6385 8978 10855

Import 11326 16176 15976 19076

Others 3775 3920 6625 8799

Total 492387 525577 546483 574124

All numbers indicate capacity in MW (net).

Notice that dualfired means full capacity to use either fuel.

The numbers given in Table 2 only gives an indication of the installed capacity. It is very likely though thatnew capacity need to be build to replace old capacity. Therefore please indicate in Table 3 yourexpectations for source of new capacity including Retrofit. Please state retrofit share in brackets.

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Table 3

1995 1996-1999 2000-2004 2005-2009 2010-2015

Coal (330)0 (150)7046 6582 7349

Nuclear 0 (78)5800 0 0

Hydro (30)284 3315 2166 2189

Gas 590 (1422)14855 (2585)12576 22203

Oil 366 1996 1186 (698)5037

Dualfired Coal/oil 0 (2333)905 4016 2335

Dualfired Gas/oil 1137 (575)4012 2088 1537

Orimulsion 0 0 (1744)309 230

Renew. 210 2209 2561 1865

Import 0 500 600 1600

Others 193 240 2775 2281

Total 2780 40878 34859 46626


4. Which factors are important for your expectation to the forecast of choice of new capacity in question3 within the time frame until 2015. Ranking with each factor given a number up till 10. 10 is the mostimportant factor and 1 is a factor of least importance.

Table 4

Determining Factor Rank Rank*

A Access to indigenous fuel ( coal, gas ) 2,9 2,7

B Fuel Flexibility 4,8 4,5

C Security of fuel supply 6,6 6,3

D Capital cost 7,2 7,2

E Fuel cost 6,5 7,2

F Requests for rate of return on investment 7,3 8,2

G Building time 2,5 2,5

H Overall reliable plant technology (eg Availability) 4,7 4,7

I Environmental considerations 7,3 6,6

J Political considerations 5,8 5,2

* weighted ranks

Breakdown of Environmental considerations. Ranks from 1 to 4 with 4 most important:

Table 5

Environmental factors Rank Rank*

K Carbon Dioxide ( CO2 ) 3,1 3,0

L Sulphuroxides ( SOx ) 2,7 2,9

M Nitrogen oxides ( NOx ) 2,6 2,5

N Others : 1,5 1,5

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Breakdown of political factors. Ranks from 1 to 4 with 4 most important :

Table 6

Political Factors Rank Rank*

O Taxes or subsidies 2,4 2,6

P Governmental regulations 2,9 2,9

Q Liberalisation 3,1 3,2

R Others : 1,5 1,3

For the highest rankings in the three tables please describe in few words your reason for the importance ofthe specific factor:

If your expectations are in favour of non-coal fired capacity based on the capacity indications in question3 you can skip directly to Question 7 below.

5. Please indicate your expectations for the technological split in your country’s new coal based electriccapacity (ref. Table 3 ). Please state retrofit share in brackets.

Table 7

1995 1996-1999 2000-2004 2005-2009 2010-2015

Sub Cr 1300 1883 1215 1438

Super Cr 400 5628 7038 3754

AFBC 0 240 235 268

PFBC 0 100 200 450

IGCC 0 335 0 1334


6. What are the most important factors for your expectations for choice of technology as described inQuestion 5. Ranks from 1 to 4 with 4 most important.

Table 8

Determining factors Rank

Capital cost 2,0

Requests for rate of return on investment 2,8

Overall reliable plant technology 2,3

Environmental considerations 2,9

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Further breakdown of environmental considerations. Ranks from 1 to 4 with 4 most important :

Table 9

Environmental Considerations Rank

Carbon Dioxide ( CO2 ) 2,8

Sulphuroxides ( SOx ) 3,1

Nitrogen oxides ( NOx ) 2,8

Others : 1,3

7. How would you respond to the statements presented below:

Table 10

Statement Yes No 00 ??

Deregulation will increase for the next 10 years 14

Long term decisions are put “on hold” due to uncertainty 12 1 1concerning upcoming liberalisation

More complex financing is expected 10 3 1

Environmental considerations will increase 14

Nuclear energy will increase in OECD Europe 8 3 3

Liberalisation will favour gas for coal 13 1

One or more CCT’s are satisfactorily proven 6 2 1 5

Coal will be burdened with environmental costs 10 1 2 1

Europe is becoming too dependant on imported coal 4 5 2 3

Local storage of gas will be imposed by the authorities 5 2 7

due to security of supply considerations

Gas will become scarce before 2015 2 8 2 2

Europe is becoming too dependant on imported gas 8 2 1 3

Notice: By 00 in column 3 is meant “No change”, whereas ?? in column 4 means “Don’t know”.

8. What would have to happen to help you overcome the barriers and accelerate the take-up of CCT?:

9. What sort of role could government policies and/or international co-operation play in encouraging thetake-up of CCT?:

10. In your opinion which are the most important factors determining the choice between coal and naturalgas in your country for fuelling new powerplants?:

Thank you for taking your time to respond to this questionnaire.

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APPENDIX 2

Recipients of the Questionnaire

Company Country

EVN Energie-Versorgung Austria

Electrabel Belgium

SK Power Denmark

Salmisaari Power Stations Finland

Charbonnages de France France

ATIC France

PreussenElektra A.G. Germany

STEAG A.G. Germany

Rheinbraun A.G. Germany

Public Power Corporation Greece

Electricity Supply Board Ireland

ENEL SpA Italy

N.V. GKE Netherlands

Statkraft Norway

CPPE Portugal

UNESA Spain

EFO Coal And Oil AB Sweden

Electricité de Laufenbourg Switzerland

PowerGen United Kingdom

Representative East European Committee

CARBOEX, Spain

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III.

EVOLUTION OF POWER GENERATIONSOUTHERN AFRICA STUDY

INTERNATIONAL ENERGY AGENCYCOAL INDUSTRY ADVISORY BOARD

by Dr SJ LENNON

August 1996

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CONTENTS

1. INTRODUCTION.............................................................................................................. 107

2. A BACKGROUND TO CLIMATE CHANGE POLICY IN THE REGION.................. 107

3. THE CURRENT ELECTRICITY SUPPLY AND DEMAND SITUATION

IN SUB-SAHARAN AFRICA .......................................................................................... 109

4. ESKOM’S INTEGRATED ELECTRICITY PLANNING PROCESS............................ 110

5. THE SUPPLY AND DEMAND PROJECTIONS............................................................ 112

6. ELECTRICITY CAPACITY ............................................................................................. 112

7. MEETING FUTURE ELECTRICITY DEMAND .......................................................... 114

8. IMPORTANT FACTORS IN CAPACITY CHOICE ....................................................... 115

9. ENVIRONMENTAL CONSIDERATIONS IN CAPACITY CHOICE........................... 116

10. SOME POTENTIAL DEVELOPMENTS TO 2015 ........................................................ 118

11. BARRIERS TO THE INTRODUCTION OF ADVANCED COAL-FIRED

POWER GENERATING TECHNOLOGIES................................................................... 118

12. ROLE AND MEASURES OF GOVERNMENT IN ACCELERATING

THE ADOPTION OF CCT ............................................................................................... 119

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1. INTRODUCTION

This study presents a perspective of Southern Africa in the context of regional development and its linkagesto Power Generation.

It must be stressed that this study, as well as the figures presented, do not necessarily reflect an accuratepicture of the region due to the short time-frame for the compilation of the document. The figures for SouthAfrica are accurate, however the regional assessments are, at best, qualitative. In addition, whilst everyattempt has been made to obtain comment on this document, the views reflected are primarily those of theauthor.

2. A BACKGROUND TO CLIMATE CHANGE POLICY IN THE REGION

The perspective presented in this study needs to be viewed in the context of the major policy elements ofdeveloping nations. As such decision making criteria would clearly be fundamentally different to thoseapplied in developed nations.

The principle elements of national climate change policy proposed for South Africa are:

• A holistic approach recognising that a proposed action in one area (eg local) could impact another area(eg regional or global).

• Sustainable development as a goal which dictates the wise use of renewable and non-renewableresources in developing the nation. In this regard, emphasis would be placed on the socio-economicdevelopment priorities of South Africa

• The ’win-win’ approach which is based upon the principal of no regrets. This is defined as taking timelyaction based on current knowledge that is justified on environmental, economic and political grounds,whether the climate change impacts are significant or not. Implicit in this approach is the understandingamongst developing nations that the responsibility for major precautionary actions and costs rests withthe developed nations.

• Legislation and control should be used only as a last resort, and then should be guided by nationalpriorities.

• Long term projects should take the possibility of climate change induced impacts into account, but notbe driven by these considerations.

• Energy policy should promote the wise use of electricity and high priority electrification programmes.At the same time, the potential to reduce costs and increase competitiveness through improved energyefficiency will ensure compatibility with climate change issues.

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• Public awareness, education and training are essential in ensuring the success of any policy.

• Factual information is a pre-requisite for decision making. As such, research and monitoring areimportant components of policy.

• International co-operation is an important mechanism for responsible development.

• Technology transfer and development are essential in avoiding the mistakes of the developed nationsand in ensuring that development is achieved with an optimised increase in emissions.

In essence the policy position of developing nations is to focus on local and regional issues, especially in thelocalisation and/or regionalisation of climate change impacts and determining how to anticipate, adapt to and,if possible, take advantage of such impacts. At the same time, they need to maximise international co-operation to ensure development is optimised and that ultimately the objective of the United NationsFramework Convention on Climate Change (UNFCCC) is met without compromising their development.This co-operation should include the transfer of Clean Coal technology (CCT) from developed nations.

This position is illustrated in Figure 1, where Figure 1a indicates a non-optimal position with developingnation’s emissions overshooting before stabilising. In this case the errors of developed nations are repeated.Figure 1b reflects an optimised situation where state of the art technology is accessed during development,with full incremental costs being borne by developed nations, and ’activities implemented jointly’ arecredibly and effectively applied. In this context it is clear that advanced and highly efficient CCT for powergeneration have an important role to play.

Figure 1

(a) (b)

Emissions

Time Time

Emissions

Target Target

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3. THE CURRENT ELECTRICITY SUPPLY

& DEMAND SITUATION IN SUB-SAHARAN AFRICA (1995 FIGURES)

Tables 1 and 2 below reflect the 1995 situation for supply and demand in the Sub-Saharan African nations

listed. (Source: Eskom Statistical Yearbook, 1995)

Table 1

Net Maximum Generating Capacity

Country Thermal

Hydro &

Nuclear Geothermal Total

% of

pumped total

storage

Angola 125 201 - - 326 0.71

Botswana 172 - - - 172 0.38

Congo 18 89 - - 107 0.23

Kenya 100 570 - 45 715 1.56

Lesotho 2 3 - - 5 0.01

Malawi 25 165 - - 190 0.41

Mauritius 278 54 - - 332 0.72

Mozambique* 97 2293 - - 2390 5.21

Namibia 147 240 - - 387 0.84

South Africa 30612 2249 1840 - 34701 75.66

Swaziland 10 40 - - 50 0.11

Tanzania 139 375 - - 514 1.12

Zaire 38 2442 - - 2480 5.41

Zambia 84 1670 - 20 1774 3.87

Zimbabwe 1056 666 - - 1722 3.75

Total MW 32903 11057 1840 65 45865 100

* includes Cahora Bassa

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Table 2 Production and Trade of Electricity (GWh)

Country Gross Imports Exports Total %of Peak kWh Totaldomestic available total demand per electri-

production (mw) capita city sold(GWh)

Angola 1042 0 0 1042 0.50 138 99 902

Botswana 1017 382 0 1399 0.67 204 999 1208

Congo 354 166 0 520 0.25 ? 226 336

Kenya 3678 187 0 3865 1.86 605 148 3222

Lesotho 0 435 0 435 0.21 80 217 380

Malawi 861 0 1 860 0.41 149 108 731

Mauritius 1047 0 0 1047 0.50 201 952 899

Mozambique 365 608 0 973 0.47 104 56 701

Namibia 1259 767 0 2026 0.97 277 1447 1795

South Africa 174715 172 3047 171840 82.70 25133 4373 153547

Swaziland 110 597 0 707 0.34 118 862 603

Tanzania 1791 11 0 1802 0.87 ? 68 1523

Zaire 5379 53 1278 4154 2.00 ? 110 ?

Zambia 8116 0 1067 7049 3.39 1108 766 6171

Zimbabwe 7811 2312 46 10077 4.85 1617 969 9036

TOTAL 207545 5690 5439 207796 100 - - -

4. ESKOM’S INTEGRATED ELECTRICITY PLANNING PROCESS

In order to clarify the position presented in the following sections, it is considered useful to put thisinformation in the context of the Integrated Electricity Planning process applied by Eskom, the largest utilityin the region.

The role of Integrated Electricity Planning (IEP) is to:

• provide the context for business planning,

• identify short, medium and long term resource needs,

• operate as a planning matrix across Generation, Transmission & Distribution,

• act as a mechanism to test options holistically and recommend an optimal development plan.

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In particular the objectives of IEP are to:

• align supply and demand options with goals and priorities,

• provide an accurate and documented, least cost package of options,

• satisfy customer needs by providing optimal value of electricity,

• ensure the financial viability of the Utility.

The process of IEP is as follows:

4.1 Forecast Energy & Load Shape

A forecast cone (range) is developed for both maximum demand and load factor. This forecastis undertaken on the basis of a base case which excludes interventions such as DSM.

↓4.2 Identify Demand Side Options

The potential means of modifying customer behaviour and usage patterns are identified andcosted out.

↓4.3 Identify Supply Side Options

All viable means of meeting demand with new capacity are identified and costed out.

↓4.4 Determine Least Cost Combination of the Supply & Demand Options

The relative merits of all options are assessed and a least cost package of supply and demand sideoptions is compiled. The impact of these options on the demand forecasts is quantified andmodelled.

↓4.5 Evaluate Risk & Uncertainty

The risks and uncertainties inherent in the least cost package are assessed to determine theprobability of successful implementation of the plan.

↓4.6 Evaluate Environmental Impact

The positive and negative environmental impacts of both the demand and supply side options arequantified and costed out if possible.

↓4.7 Select & Justify Preferred Plan

In applying the IEP process, a rigorous analysis is undertaken of all possible options open to the industry. Inthis regard it is clear that CCT are assessed using the same criteria as all other options. This leads to thelogical conclusion that the uptake of CCT is a direct function of their ability to compete with the other options(both supply and demand) on a cost, availability and reliability basis.

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It should be noted that there are discussions at Government level regarding the desirability of opening up thegenerating sector to private and foreign ownership, as well as restructuring the distribution sector. This wouldclearly impact the IEP process.

5. THE SUPPLY & DEMAND PROJECTIONS

The following figures (Table 3) are for South Africa with an assumed long term economic growth rate ofbetween 1,5% and 3,5%. The midpoint of these economic projections has been used. The Southern Africanperspective is presented in a qualitative sense only.

Table 3

ActualI

Projected

1995 2000 2005 2010 2015

Capacity required (MW) 29 500 32 000 39 500 47 000 53 200

Capacity available (MW) 36 314

Annual maximum demand (MW) 25 133 30 000 35 250 41 500 47 500

Energy GWh 153 547 180 000 220 000 240 000 270 000

(Source: Eskom Integrated Electricity Plan - 5)

These figures include a possibly optimistic reserve margin of 12%, but exclude DSM measures aimed atreducing peak demand by 7300 MW by 2015.

The increase in electricity demand in the region is expected to be a relatively small percentage over and abovethe figures presented in Table 3, due to the far lower demand in other countries in Southern Africa.

In addition to the above it should be noted that significant over-capacity exists in the region as a whole.

6. ELECTRICITY CAPACITY

Under the current scenarios it is unlikely that additional capacity will be required in the region before the year2010. In particular, the excess capacity in the region may be optimally utilised via the Southern AfricanPower Pool. Issues such as the reliability of long transmission lines, coupled with individual, nationalpriorities could, however, result in additional capacity being built before this time. In approximately 2014additional peaking plant could be required in South Africa, once plant in storage has been re-commissioned.This is likely to be pumped storage. Mid merit/peaking plant may however be required before this date,depending on the success of planned DSM interventions.

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The primary source of electricity in South Africa is likely to remain coal given the significant low cost

reserves available, as illustrated in Figure 2. The choice of coal combustion technology is dependent on the

relative economics.

Figure 2

South African Energy Reserves (MWe)

In Southern Africa the primary growth is likely to be in hydro power with some (limited) potential for growth

in natural gas.

The current energy reserves and electricity capacity for Sub-Saharan Africa are reflected in Table 4 below.

Table 4

Potential Reserves (MWe) Current Installed Capacity (MW)

Thermal 36 826

- coal 160 000

- oil 2 130

- gas 7 600

Nuclear 70 000 1 840

Hydro 142 000 9 206

Geothermal ? 50

Nuclear53 000

Hydro7 500(includes pumped storage)

Gas350

Coal100 000

Total 380 000 MWe

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7. MEETING FUTURE ELECTRICITY DEMAND

The prime source for meeting electricity demand in the region in the short to medium term is the currentexcess capacity in the region. Any increase beyond this capacity will, in all likelihood, be met predominantlyby coal in South Africa, and by hydro power in the other Southern African nations.

In addition a Demand Side Management programme in South African has targeted the following alternativesto capacity expansion:

Table 5

DSM Technique Impact by 2015(MW)

Interruptibility 200

Load shifting 600

Energy efficiency 500

TOTAL 1 300

In spite of this situation, future supply side options for South Africa are currently being evaluated for futureapplication. In particular the highly uncertain range of potential growth in demand dictates a pro-activeand flexible approach to supply side alternatives.

These options being evaluated fall into 3 main categories:

1) Plant in Storage

The technical and commercial basis for re-commissioning some 3540 MW of mothballed plant isbeing established

2) Established technologies for new plant.

Options are evaluated on the basis of lifecycle costs, unit size and lead times. These options currentlyinclude:

• Conventional (supercritical) coal fired,

• Combined cycle gas turbine,

• Conventional nuclear (PWR),

• Hydro,

• Independent power production,

• Co-generation,

• Power imports.

3) New Technologies

This category assumes a new capacity requirement in the first or second decade of next century, andconsists of the evaluation of a variety of new (for South Africa) and emerging technologies with theobjective of reducing:

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• Lead time,

• Capital and operating costs,

• Environmental impacts,

• and optimising unit size and load following capability.

Technologies to be investigated include:

• Fluidised Bed Combustion Plant (Utilisation of Discard Coal),

• Integrated Gasification Combined Cycle Plant,

• Gas Cooled (Pebble Bed) Nuclear Reactor Plant,

• Underground Compressed Air Energy Storage Plant,

• Underground High Head Pumped Storage Plant,

• Coal Fired Gas Turbine Plant,

• Municipal & Industrial Waste: Combined Heat & Power Plant,

• Solar Thermal Power Plant.

8. IMPORTANT FACTORS IN CAPACITY CHOICE

The choice of technology for future capacity is guided by numerous decision making factors. These are listed

in approximate order of importance below:

• Capital and operating cost,

• Plant reliability and availability,

• Access to indigenous, low cost fuel,

• Lead times,

• Operational flexibility (base load versus peaking etc),

• Water availability,

• Environmental considerations (likely to move up in order of importance with time),

• Security of fuel supply,

• Local capacity to sustain technology (skill, infrastructure etc),

• Funding availability,

• Political considerations.

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9. ENVIRONMENTAL CONSIDERATIONS IN CAPACITY CHOICE

Environmental considerations play an extremely important role in expansion planning, however this role isat a far more operational level than for developed nations. In this regard the focus is on local and regionalenvironmental impacts and benefits, with a lower priority being given to global impact. For example, theintroduction of low-smoke coals to reduce urban air pollution will, in effect, increase CO2 emissions due tothe energy required in the devolatilisation process as well as the lower energy content of the product. Theprimary environmental issues are presented with a South and Southern African perspective below. It shouldhowever be noted that the attention given to environmental matters varies considerably from country tocountry in the region.

These issues clearly receive varying attention as components of environmental impact assessments on aproject by project basis.

9.1 WATER QUALITY & AVAILABILITY

The availability of water is one of the critical environmental issues in Southern Africa. Water supplies arehighly variable, both in terms of quality and quantity. Technology choices are often strongly influenced bythe amount of water used as well as the impact on water quality.

9.2 LAND MANAGEMENT / ECOLOGICAL IMPACTS

Whilst land is generally readily available, the ecological impacts of a particular technology requireassessment, especially in areas where eco-tourism is an important consideration. The inundation of landby hydro projects is an issue which requires particular attention.

9.3 AIR QUALITY

Power plant emissions receive varying degrees of attention. In general a holistic approach is adopted withrespect to Air Quality. In South Africa air quality is assured via the use of a ’best practicable means’approach. This implies primary attention is paid to particulate removal, and then the impacts of SOx andNOx are managed via ambient air quality requirements. The Department of Environmental Affairs andTourism are currently investigating this management process. Acceptable air quality levels are maintainedvia the combustion of low sulphur coals and tall stacks.

It should be noted that extensive research into Air Quality has been undertaken in the main Power Generationregion, Mpumalanga, over a 15 year period. This research has clearly demonstrated the efficacy of thecurrent Air Quality management processes in containing local and regional air and rain qualities toacceptable levels. In this regard, air quality in this area has improved by an average of 4% pa for the last 10years, greatly allaying concerns related to exceedance of local and regional air pollution standards. WHOlevels for ambient air quality are rarely exceeded.

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9.4 WASTE MANAGEMENT

The production of waste, especially large quantities of fly ash from the combustion of high ash coalrequires careful management. Ash disposal, utilisation and rehabilitation of disposal sites is an importantcomponent of technology assessment. In addition, the water used in waste transport and disposal is animportant consideration in technology choice.

9.5 SOCIO-ECONOMIC IMPACTS

Socio-economic development is the highest priority in the region. As such, the choice of a supply sideoption and the attendant environmental controls, is strongly dependent on its impact on society as a whole.For example, if it is a matter of choice between utilising resources for an electrification programme versusfitting additional pollution control equipment, where such equipment is an environmental luxury, then theformer has precedent. The term “environmental luxury” implies a “nice to have”, which is not justified onscientific or economic grounds. This example is well illustrated in South Africa where, due to thecombustion of low sulphur coal, coupled with tall stack dispersion, air and rain quality levels in the regionof power generation are maintained at acceptable levels. As such, the motive to install additionalenvironmental controls eg desulphurisation, is limited, especially when one considers the alternativeapplication of resources. In particular it has been shown that, in the long term, electrification of urban areasresults in a significant improvement in currently unacceptable pollution levels due to the domesticcombustion of coal. In this regard electrification may be regarded as a CCT.

It should be noted that a significant percentage of people (69%) are unlikely to get rid of their coal stovesin the short to medium term - even after electrification. Therefore, in the interim (medium-term), anintegrated approach of continued electrification, fuel optimisation (low-smoke fuel and combustionappliance improvement) and housing energy efficiency (insulation) will be followed to reduce theunacceptable urban residential air pollution levels.

9.6 SERVITUDE’S

The routing of transmission lines through ecologically sensitive areas is the subject of comprehensiveEnvironmental Impact Assessments in some countries in the region. Some projects to increase the capacityof other countries to undertake such studies are currently underway. Soil erosion initiated by poorservitude management can be a particular problem, as can the impact of structures and lines on the localecology, especially wildlife such as birds.

9.7 GLOBAL IMPACTS

As developing nations, the issue of CO2 emissions from generating plant receives relatively limitedattention. The approach typically adopted is one of striving to improve plant efficiency, reliability andavailability, with attendant CO2 emission reduction benefits. There is little motivation to select atechnology which produces less CO2 merely for the sake of it or at a cost premium.

Whilst policies are still being formulated, it is considered that, if full incremental costs are covered bydeveloped nations, CO2 emission technologies could be viewed with more favour.

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10. SOME POTENTIAL DEVELOPMENTS TO 2015

• Industry restructuring will play an important role for the next five years,

• Environmental pressures, regulation and requirements will increase,

• The Southern African Power Pool will play an important role in balancing supply and demand,

• Natural gas may be used for power generation,

• Coal and hydro will continue to be the main sources of primary energy for power generation,

• CCT will only be introduced once increased capacity is required and if they meet cost and reliabilitycriteria.

11. BARRIERS TO THE INTRODUCTION OF ADVANCED COALFIRED POWER GENERATING TECHNOLOGIES

Clearly the most significant barrier to the uptake of CCT in Southern Africa is the current excess ofgenerating capacity in the region, coupled with generally energy intensive economies and a significantpotential for financially viable demand side measures. It should however be noted that projections foreconomic growth in the region are highly variable with ’aspiration figures’ as high as 6% being quoted.Given the fact that economic growth and electricity demand growth are still directly correlated, a 6%growth rate would create the need for a major capacity expansion (up to 2300 MW pa) from the year 2004.This clearly offers immense opportunities for economically competitive CCT.

If one assumes such opportunities for CCT, then consideration must be given to other potential barriers totheir introduction. These include:

• Perceptions of unreliability and high operating costs,

• Limited local skills to adapt to new technologies,

• Limited support infrastructure to cater for new technologies,

• Competition from other technologies and fuels such as hydro, gas and possibly nuclear,

• The need to assess performance in a Southern African environment, eg combustion of local low gradecoal etc.,

• The relative efficiency of current plant (34.3% average for 1995).

It is considered unlikely that CCT will displace existing plant, especially given current plant efficiencies.

The relatively young age of current operational coal fired power stations in South Africa (11-15 years)precludes their upgrading to CCT without efficiency or water consumption penalties. It is thereforenecessary for CCT to replace this plant upon decommissioning or to penetrate the growth market. CCTcould also replace current older plant in mothballs.

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It should further be noted that the current South African practice of burning low-grade (high ash, lowsulphur) coals for Power Generation results in extremely low primary energy costs. This makes it difficultfor competing technologies utilising other fuels to penetrate the Power Generation market - as they are 2-3 times more expensive on life cycle costing. Clearly CCT combusting low-grade coal, with morefavourable capital costs and efficiencies, will receive serious consideration for replacement plant.

The major energy resources in Southern Africa are coal and hydro. As such, the focus in the region outsideof South Africa will be on hydro development. Individual national priorities and non-optimal commercialattitudes can however act as obstacles to this development.

Political issues are considered to present a minor to non-resistant barrier to the introduction of CCT.Resources, especially funding, are often major constraints in any supply side option in Sub-Saharan Africa.In this regard, innovative funding options/aid packages are required.

12. ROLE AND MEASURES FOR GOVERNMENT IN ACCELERATING THE ADOPTION OF CCT

In assessing the options open to both Governments and Industry in facilitating the rapid uptake of CCT, itis assumed that the need for additional, or replacement, capacity exists. This is clearly not the case inSouthern Africa given the current excess capacity, potential for DSM and the hydro capacity in the region.Nevertheless some ideas from the perspective of a developing nation are presented below.

12.1 CATALYSE ECONOMIC GROWTH

In a Southern African context it is obvious that economic growth is an important driver in increasedelectricity demand, which is an obvious precursor for the uptake of CCT once excess capacity isexhausted. In this regard, international trade protocols and the need to avoid discriminatory trade practices,especially on environmental grounds, is critical.

It should however be stressed that Governments and Industry catalysing economic growth in developingnations is no guarantee that CCT will be adapted to meet electricity demand. There are numerous selectioncriteria (as detailed in previous sections of this study) which will be applied. Some of the measures whichfollow are proposed to enhance CCT in the selection procedures.

12.2 APPLICATION OF THE UNITED NATIONS FRAMEWORK CONVENTIONON CLIMATE CHANGE

Two of the most important criteria for power generation technology selection are cost and reliability. Inthis regard developing nations feel that the UNFCCC should be far more rigorously applied by theGovernments of developed nations in meeting the full incremental costs of more efficient CCT overcurrent conventional technologies. If this involves additional costs of redundancy to ensure reliabilitylevels equivalent to current plant, then such costs should also be covered.

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It is not considered appropriate or equitable for the Governments of developing nations to fund the“premium” costs of CCT.

In addition the current pilot phase of ’Activities Implemented Jointly’ (AIJ) should include an assessmentof the potential for CCT to be used as future AIJ projects.

12.3 RESEARCH, DEVELOPMENT & DEMONSTRATION

Whilst it is accepted that virtually all CCT are at or beyond the advanced pilot or demonstration stages, itis essential that such programmes be undertaken in a variety of countries. The perceptions around costs,availability and reliability will only be addressed if pilots are undertaken in the countries of finalapplication, especially developing nations. This will also enable CCT to be tailored to meet unique localconditions and develop enabling capacity for ultimate application. In this regard, incentives for Clean CoalTechnology pilot plants in developing nations should be developed.

12.4 TECHNOLOGY TRANSFER

In most countries, especially developing nations, the current technological infrastructure and capacity isaligned with current technologies. There are limited skills available to develop parallel capacity in CCT.As such it is suggested that intensive technology transfer programmes are entered into to develop thiscapacity. Technology transfer from developed to developing nations must include consideration of:

• funding,

• long term training in the receiving nation,

• development of a technological support infrastructure,

• technology adaptation to local conditions,

• lifecycle funding.

It must be stressed that technology transfer must be applied in the most holistic sense possible. It isnecessary to have systems in place that support the technology for its lifecycle, not merely to thecommissioned stage. In this regard, the ongoing capacity building component of technology transfer is acritical success factor.

12.5 COSTS, AVAILABILITY AND RELIABILITY

In order for CCT to penetrate the market, they must clearly demonstrate business advantages over currenttechnologies. In this regard, further efforts to reduce costs and improve availability and reliability should beintensified. It is considered that CCT must demonstrate significant advantages over current technologiesbefore they will be widely applied in developing nations. In this regard the pilot programmes mentionedabove could have an important role to play.

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12.6 DIRECT INTERVENTION

In developing nations, governments are often the main catalyst of new energy development, as motivated bya variety of political factors and rarely driven by economic considerations. Whilst direct intervention isobviously a potential mechanism to increase the speed of application of CCT, it is generally non-sustainablein economic terms, especially where excess capacity exists.

12.7 DEVELOPMENT OF HUMAN CAPACITY

In many utilities in developing or under-developed nations, significant efficiency improvements are possiblevia the effective application of current technologies, ie with what is already in place. In this regard, moreattention needs to be placed on the training of skilled technical and managerial personnel. In particular, theorganisational skills in initiating and managing inter-utility projects across national boarders need to bedeveloped. The greater local availability of such skills would be extremely useful in optimising efficienciesin a region such as Southern Africa.

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REGIONAL CHARACTERISTICS OF SOUTHERN AFRICA.

Expected load growth in power 23,7generation till 2015 (GW capacity)

Rough projection of split of growth by Hydro 25 ] ?

fuelling type eg coal, nuclear, gas, hydro Coal 75 ]

Nominal coal capacity (GW) installed 18,8since 1980

Of coal capacity installed since 1980, 0% how much (GW) is supercritical, how much other advanced coal eg PFBC, IGCC

Major options other than coal available Hydro, nuclear, gastill 2010, eg gas CCT

Are options likely to change after 2010 Noeg foreseen rise in gas price

Regional attitudes towards new coal Clean coal technology has potential but musttechnology eg, capital cost and financing, prove itself against competing options on a cost,regional environmental trends, availability and reliability basis environmental acceptability of coal

Specific present barriers to installing new • Hydro focus in the regioncoal technology • Perceptions of unreliability and high operating costs

• Limited local skills to adapt to new technologies

• Limited support infrastructure to cater for new technologies

• Competition from other technologies and fuels such as hydro, gas and possibly nuclear

• Need to assess performance in a Southern African environment, eg combustion of local low grade coal etc

• The relative efficiency of current plant (34,3% averagefor 1995)

• Age of current plant (relatively new)

Ideas for overcoming these barriers • Catalyse Economic Growth• Application of the United Nations framework • Convention on climate Change• Research, Development & Demonstration• Technology Transfer• Costs, Availability & Reliability improvement• Direct Intervention by Governments• Development of Human Capacity

Any other comments Local & regional development takes precedent over technology choices

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APPENDIX IV

OECD ASIA/PACIFIC

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125

IV.1

REGIONAL STUDIES ON EVOLUTION OF POWER GENERATION

AUSTRALIA AND NEW ZEALAND

INTERNATIONAL ENERGY AGENCYCOAL INDUSTRY ADVISORY BOARD

Climate Change Committee

18th August, 1996

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CONTENTS

1. EXECUTIVE SUMMARY.................................................................................................... 127

2. INTRODUCTION.................................................................................................................. 132Australian Competitive Position................................................................................... 133New Zealand Competitive Position.............................................................................. 133Methodology ................................................................................................................. 133

3. LOAD GROWTH................................................................................................................... 134Load Growth to 2015.................................................................................................... 135Reserve Margin ............................................................................................................. 136

4. ENERGY GENERATION MIX............................................................................................ 137Australia ........................................................................................................................ 138New Zealand ................................................................................................................. 139Energy Mix.................................................................................................................... 139

5. ATTITUDE TO NEW GENERATION TECHNOLOGY.................................................... 141Retrofitting Existing Plants........................................................................................... 142Determining Factors for New Plant.............................................................................. 142Environmental Factors .................................................................................................. 143Political Factors............................................................................................................. 143New Coal Technology .................................................................................................. 143Related Energy Issues................................................................................................... 144New Generation Capacity, Recent Cases ..................................................................... 146

6. ACKNOWLEDGEMENTS ................................................................................................... 147

7. APPENDIX ............................................................................................................................ 147Questionnaires............................................................................................................... 148References ..................................................................................................................... 152

This document and the contents are copyright.

Sligar and Associates Pty. Ltd.,ACN 003 904 809 - 10 Bond St.,Mosman NSW tel: 61 2 9960 5996Australia 2088 fax: 61 2 9968 4067

This survey and analysis was prepared by Dr J Sligar on behalf of Dr D Klingner of RTZ-CRA, a member of theGlobal Climate Change Committee, to present to that committee. The committee is a sub group of the CoalIndustry Advisory Board of the International Energy Agency.

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This document is the contribution on behalf of Australia and New Zealand to the world study on theassessment of the overall choice of coal fired technologies for the period to 2015. The present energy supplyconditions in this region are well defined as is the historical development of the industry in these countries.

Australia and New Zealand constitute a region of the world where government has recently stronglypromoted competition in the electric power industry and moved away from a planned economy. This hasdeveloped an opportunistic approach and less certainty in the type and timing of new generation plantadditions.

This report focuses on the following factors in an attempt to clarify the position on likely new generationtechnology in Australia and New Zealand.

Load growth predictionsStrategic energy mix changesAttitudes to new generation initiativesSpecific issues to do with Clean Coal Technology

LOAD GROWTH PREDICTION

The first factor of importance is that of expected load growth in the region over the period. The competitivemarket situation has removed the responsibility of government to prepare official load predictions,although some advisory predictions are still available. Competitive existing or potential generatingorganisations need to prepare their own predictions as part of their decision analysis on installing new plantor retrofitting older installations.

The load growth in Australia and New Zealand is expected to average 2% through to 2015. There is nosign of growth comparable to other parts of Asia, which are between 8 and 12%. This low predictedgrowth, coupled with the existing reserve margin in some regions and a highly competitive situationdeveloping, will lead to competitive generation initiatives in the near future.

New generation plant will be incremental in nature and, with the deregulation of the gas market inAustralia, it is expected that the reduced price of gas arising from this will tend to favour a higherproportion of new capacity using gas as fuel.

A major proportion of existing coal fired plant has been retrofitted in the relatively recent past and thereare plans to refit further coal fired plant before 2000. There may be minor new technology initiatives inthese refits. There are a few plants where retrofitting of new coal technology, such as the IGCC plant atWabash River in the USA, could be applied but this is considered unlikely at this stage.

ENERGY MIX

The next factor is the potential change in strategic energy mix for Australia and New Zealand. Previouslythis was securely under government control but one of the outcomes of the competitive market isgovernment giving up control over generation planning and the strategic fuel and base/intermediate/peakingload mix of generation plant. The generation entrepreneur can now select any energy source and does soprimarily on financial grounds to ensure an adequate return on investment. The technology also needs to beacceptable to the source of finance for the project. This generally does not favour newer technologies overconservative, reliable but perhaps not as efficient or environmentally friendly technologies.

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Existing or prospective generation organisations were commercially hesitant about predicting timing,capacity or source of energy for new plant. However estimates have been made based on a number of sourcesand statements at interviews. The table below, although incomplete, provides a picture of new generationinstallations to 2015 which are considered to be highly likely. It represents a minimum set of additional plantas prospective new generators have not all been identified.

Table 1Likely New Generation Plant, Australia MW

2000 2005 2010 2015

Coal 800(820R) 1400

Water, hydro gas 1900 3500(120R) 500(120R) 850

Gas or coal, uncommitted 1000 1000

Renewable, all R, retrofit older plant 100 500 2000 3000

By way of explanation, most existing and prospective generators are committed to gas in the short term.It is generally hoped that the introduction of a deregulated gas market in the near future will reduce theprice of gas to a more competitive level. There is at least 1000 MW of gas available on the east coast and500 MW on the west coast which is confidently expected to be utilised by 2000. These units will be neededfor peaking but will find a suitable niche in the overall market structure, depending mainly on howcompetitive the price of gas becomes.

Sourcing gas beyond 2000 is more difficult and it is possible that different utilities are viewing the samegas resource as potentially “theirs”. Again this position will be clarified with gas market deregulation andsubsequent competition. A number of utilities saw the future as gas, if available, and coal if not, which canbe seen in some entries for gas or coal, uncommitted.

With respect to renewables, one state passed a law last year setting an annually reducing cap on thequantity of carbon dioxide which could be sold as electricity in their territory by every individualdistributor. This was aimed at encouraging demand side management which could be included as negativecarbon dioxide. As a result of this, distributors have promoted demand side management, linked with newgas cogeneration plants, and promoted solar and wind in order to minimise the carbon dioxide content intheir power supply. Most are selling “green energy” at a premium. In essence they have to compete forthe purchase of energy on the grid but keep their overall purchase of equivalent carbon dioxide below acap value which is reducing annually to the year 2000.

In addition, one utility has invested heavily in solar energy in an attempt to reduce the cost of solarcollectors to $1 per watt before the year 2000 in anticipation of dual competitive and carbon dioxidetargets.

It is critical to understand the altered implication of key factors when considering a competitive market asopposed to a monopoly. As an example, there is no longer any link between apparent reserve margin andthe installation of new plant. New plant is installed when a competitor considers that there is acommercially viable niche in the market structure. This can be seen by comparing the expected growthfigures with the proposed generation additions.

These predictions will distort the ABARE predictions of energy sources for generation in Table 2,increasing the gas proportion and decreasing the others in the short term.

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Table 2Energy Sources for Generation, %

1995 2000 2005 2010

Coal 84 85 84 82Oil 2 1 1 1Gas 11 11 11 13

Water, hydro 3 3 3 3

The Table for New Zealand has similar provisions to those for Australia.

Table 3Likely New Generating Plant, New Zealand MW

2000 2005 2010 2015

Coal

Water, hydro (250R)

Gas 450 (300R) 100

Gas or coal, uncommitted 700

Renewable, all 250 100

R, retrofit older plant,

hydro and conversion of

coal power stations to gas.

ATTITUDES TO NEW GENERATION TECHNOLOGY

The third factor was the attitude of senior executives within existing or prospective generatingorganisations to new plant decisions, no matter what technology was being considered. Ten organisationsrepresenting existing and potential generators responded to the questionnaire with the following weightingon the major factors:

Factor identification %

1 Access to indigenous fuel 4

2 Fuel flexibility 7

3 Security of fuel supply 7

4 Capital cost 11

5 Fuel cost 9

6 Required return on investment 17

7 Construction time 9

8 Overall plant availability 8

9 Environmental considerations 13

10 Political considerations 13

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The critical importance of return on investment, political and environmental considerations is obvious.

The questionnaire requested more specific analysis of the environmental and political factors with thefollowing replies:


1 Carbon dioxide formation 30

2 Sulphur oxide formation 23

3 Nitrogen oxide formation 27

4 Other environmental factors 20


1 Taxes or subsidies 23

2 Government regulations 33

3 Promoting competition 30

4 Other political factors 13

The voting in these areas showed the importance placed on carbon dioxide and nitrogen oxides in theenvironmental arena and of government regulations and promoting competition in the political area.

More specific questions were addressed to those contemplating new coal generation. It was generallyagreed that conventional pf sub-critical coal technology would be installed through to the year 2000. Theintroduction of IGCC plant would start by 2005 and be preferred by 2010. AFBC and PFBC were seen tobe available now for specific applications, mainly concerned with burning high sulphur coals effectivelywith low environmental effects.

It should be noted that there was a second group which saw efficiency as paramount and they wouldpresumably utilise new coal technology sooner if it were financially competitive.

NEW COAL TECHNOLOGY

These questions continued comparing plant and environmental factors for these technologies in greaterdetail. The factors and responses are set out below:

Plant installation factor %

1 Capital cost 20

2 Return on investment 34

3 Plant availability 20

4 Environmental considerations 26

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Environmental sub set factors %

1 Carbon dioxide formation 30

2 Sulphur oxide formation 26

3 Nitrogen oxide formation 27

4 Other environmental factors 17

This was followed by a series of short queries examining different aspects of the energy situation. Theresults are presented in summary :

Response

Issue yes no no change not know

Deregulation will increase over time 6 1

Deregulation uncertainty will slow new plant 3 4

More complex financing will develop 7

Environmental requirements will increase 7

Nuclear energy may be utilised 6 1

Deregulation will favour gas over coal 7

At least one CCT is adequately proven 5 1 1

Coal will have extra environmental costs 6 1

Australia is too dependent on exported coal 3 2 2

Gas storage will be required for availability 4 3

Gas will become limited before 2015 2 4 1

Australia is too dependent on exported gas 5 2

CLEAN COAL TECHNOLOGY

A major question not amenable to numerical answers was to define the barriers to or issues concerned withthe adoption of Clean Coal Technologies. The following issues were raised, some at a number ofinterviews.

A list of the issues raised in answer to this query is set out below:

Competition and economics issues

• When can CCT provide an acceptable return on investment?

• When will CCT achieve competitive capital cost?

• How can the lead time for this plant be reduced?

• Will this technology be competitive with gas cogeneration?

• Private power groups and their bankers were more conservative than previous utilities.

• Competitive conditions did not promote coal fired capacity of any type.

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Technical issues

• When will CCT be proven for larger capacities, >500 MW?

• When will CCT have proven availability?

• When will CCT be an acceptable risk for financiers?

• There is a lack of information on technical and cost factors.

• Manufacturers are not offering CCT plant, even as non conforming bids.

• There is a need for more demonstration plants.

• In some cases it was felt that no CCT was proven.

• The term CCT was not well understood in some cases.

Environmental issues

• The environmental anti coal lobby is growing stronger.

• There are other low cost carbon dioxide mitigation technologies.

The questionnaires have provided a wealth of information, some of which was well known but some ofwhich needs to be addressed by various sectors of the industry for CCT to be taken up at a rate which willpermit coal to continue to be utilised in a competitive and environmentally acceptable manner.

2. INTRODUCTION

The Global Climate Committee of the Coal Industry Advisory Board ( CIAB ) is undertaking a study ofthe Evolution of Energy Efficient Coal Fired Generating Technology. This present report covers the regionrepresenting Australia and New Zealand for inclusion with the other regional studies to develop a worldperspective on this matter.

The objective is to demonstrate, from the view of industry, how far advanced coal fired power generationoptions exist for take-up in the near to medium term, and the conditions which are necessary for take-upto occur or be accelerated.

The three regions follow OECD definitions and cover North America, OECD Europe and Asia/Pacific.This report covers part of the latter region.

The report was to address likely load growth over the following 10-15 years and changes in the energygeneration mix for that period. It was to cover in some detail attitudes to the adoption of clean coaltechnology in retrofitting existing coal fired plant, adoption of new technology steam cycle plant andmovement towards adoption of combined cycle technologies.

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Australian Competitive Position

In Australia the Council of Australian Governments (COAG), which is an organisation including thefederal and all state governments, has made decisions on improving the competitiveness of a number ofindustries. The power industry is one of these industries. The gas industry is an associated industry wherederegulation is also proceeding. The decisions involve the staged development of a highly competitivesituation in what were strictly monopoly energy supply conditions.

To this end the National Grid Management Council (NGMC) is developing a set of competitive rules forthe operation of the power industry in the States of New South Wales, Queensland, South Australia,Tasmania and Victoria. This will provide a free market for electricity in the region. This is beingimplemented now with separate competitive markets in New South Wales and Victoria. These will becombined into a single market with South Australia in the near future. Initially large users of energy willbe able to purchase from any supplier. The smaller users will be given a choice in due course.

Queensland and Tasmania will join this market when appropriate high voltage interconnection is made.

The grids in Western Australia and the Northern Territories are too remote for interconnection and willremain separate systems but with competitive elements.

For the time being the States of Queensland, South Australia and Western Australia, through theirrespective state power industry organisations, will have the responsibility to ensure supply to customers,continuing their traditional roles.

Australia is thus in a transition period with separate competitive markets being brought together aspolitical and technical impediments are overcome. The NGMC has effectively become the organisationspeaking for, and maintaining data for, the States of New South Wales, Queensland, South Australia,Tasmania and Victoria. Western Australia is operating as an independent organisation providing data forthat State, as is the Northern Territory.

New Zealand Competitive Position

New Zealand has progressed beyond Australia in developing competition and there is a competitive marketoperating throughout the country. No overall prediction of the future load growth of the industry is made;it is up to existing operators or prospective operators to predict load growth and decide when it iscommercially viable to install new plant or make any other move in the system.

Methodology for Assessment

Some of the content of information requested for this survey was considered to have commercialsignificance. Contributors were requested not to answer questions which were considered to havecommercial implications. This meant that the report could be issued without any confidential provisions,albeit losing some data content. In spite of these limitations, there was a high level of co-operation and atthe conclusion of the information gathering there were few questions left unanswered.

The methodology for assessment was in the form of a questionnaire sent to representative organisations,with follow up interviews with every organisation, most of these being face to face and a few by telephone.The data obtained was summarised to obtain an overall perspective of opinions.

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A questionnaire which the European Region had used was provided with the brief for guidance. A copy ofthis questionnaire appears in the appendix. This questionnaire was based upon a relatively centrally basedeconomy, where information on likely load growth and decisions on strategic energy mix and preferrednew generation technology were under some form of central control for a country or region.

Conditions in the electric power industry in Australia and New Zealand are significantly different fromthis, so that changes needed to be made to the European questionnaire while retaining the intent of theoriginal document.

The prime difference lay in the government promoted competition within the industry in these countries.Various organisations have the responsibility to produce documents on likely load growth predictions, withthe primary one titled “Statement of Opportunities for Power Generation” covering the following 10 yearsissued by the NGMC.

These were used together with opinions from those organisations on further growth to 2015 to answer thisaspect. This involved redrafting a new questionnaire on this topic, a copy of which appears in the appendix.

The organisations with the legal responsibility to provide load predictions were requested to provide datafor this study in accordance with the modified questionnaire. The results were summated and appear laterin this report.

The questions concerning energy mix changes and the industry attitude to new coal fired generation plantwere quite a different matter. The government in Australia and New Zealand now have very little controlover the technology to be used in new generation plant nor on the preferred strategic energy mix for thecountry. New plant is commissioned when a potential generation organisation considers that thecommercial conditions are appropriate. These organisations maintain a watching brief on both the loadgrowth and competitive action, and also on the potential technologies to see when a specific application isappropriate for development.

A modified questionnaire was developed from the European model to gain some insight into this processand in particular to determine the attitude of participant organisations towards coal and coal technologiesin their deliberations. A copy of this questionnaire appears in the appendix.

A group of nominally Australian and/or New Zealand power generation or potential power generationorganisations were asked to reply to the modified questionnaire on generation. It was understood that thequestions were potentially commercially sensitive and this was taken into account where possible. Allresults were summated in any case to conceal individual replies. The results appear later in this report.

3. LOAD GROWTH

For an effective understanding of likely generation changes a knowledge of load growth for a particularregion or country is an essential component, as is the rate of older plant being retired from service. Loadgrowth is covered below.

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In a planned economy there is an organisation whose responsibility it is to monitor various factors andpredict the load growth for that economy. This is used as a basis for new generation plant and transmissionline additions. In a competitive economy this situation may or may not apply.

In Australia there is no legislative requirement for any organisation to provide a load growth forecast.However in the regulations governing the power industry regulating organisations there is a requirementfor load growth forecasts for the following ten years to be made available and revised annually. These areof an advisory nature to assist existing and potential generators in deciding if and when new plant shouldbe installed.

It should be noted that ABARE, a federal government organisation, also produce predictions of energygrowth as part a set of wider economic predictions.

The National Grid Management Council (NGMC) is responsible for the annual production of load growthforecasts for the following ten years for the South East of Australia (the States of New South Wales,Queensland, South Australia and Victoria). The predictions made by NGMC are published as “Statementsof opportunities for power generation” to assist power generation entrepreneurs to make informeddecisions on the need for new power generation plant for a particular power system. In South EastAustralia load growth forecasts exist to 2007, made by a number of organisations which togethercontribute to the NGMC totals.

Western Power prepares load forecasts for the State of Western Australia. Power and Water Authorityprepares load forecasts for the Northern Territory. The sum of these and that from NGMC provides a totalfor Australia, except for some small isolated regions.

In New Zealand there is no central body whose responsibility it is to provide load growth forecasts. Everyexisting and potential generator must develop its own load forecasts to enable it to make decisions on newgeneration timing and capability. Predictions exist from the previous government controlled situationwhich have been used as a basis for the predictions set out in this document.

As this IEA study requires a time frame to 2015, discussions were held with the various authoritiesresponsible for these regions to determine the extent of internal load growth forecasts beyond ten years andso develop an overall estimate beyond the official predictions. Time frames of forecasting in differentorganisations ranged from the necessary ten years to twenty years.

The European questionnaire was revised to incorporate local conditions and appropriate organisationsrequested to comment. The answers to questions are analysed in the respective sections.

Question 3 on load growth to 2015

The question of “official” estimates of load growth in Australia is now complex. The NGMC prepares a“Statement of opportunities” for the States of New South Wales, Queensland, South Australia and Victoria.Western Power and PAWA prepare load growth forecasts for Western Australia and the Northern Territoryrespectively.

All participants referred to these documents as the definitive statement for the following ten years. Mostorganisations did not go beyond ten years and rates of growth existing then have generally beenextrapolated to 2015 to produce the table of load growth expectations.

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It became apparent that there were differences in the bases on which predictions were made but theseappeared to be a small proportion of potential errors in long range prediction and were ignored. There isobviously a case for national and/or international standardisation in this area.

The Australian predictions were generally in the form of three scenarios, low, medium and high growth.The medium growth figures were used. These scenarios did not link well with the IEA “capacityconstraint” case, which combines baseline GDP and population assumptions with rising energy prices. Thecompetitive market in Australia is experiencing reduced energy prices and this trend is expected tocontinue. This factor needs to be taken into account when integrating these findings with those from othereconomies.

Table 4Load Growth, Australia

MW GWh

1995 25,800 157,000

2000 29,800 160,000

2005 33,600 163,000

2010 37,800 167,000

2015 42,600 170,000

The position in New Zealand was similar with no official load growth forecasts, every generator having toestimate on its own account. Previous predictions had presented three scenarios and the continuation ormiddle prediction has been used as a basis for this table.

Table 5Load Growth, New Zealand

MW GWh

1995 7,900 33,000

2000 8,100 37,500

2005 8,600 41,000

2010 9,000 43,000

2015 9,500 44,500

Question 4 on reserve margin

There was some hesitation in answering this question in Australia because of the competitive position andthe fact that most generators no longer had the responsibility to provide adequate reserve margin. Gridmanagement organisations provided indications of load growth and potential shortcomings, and it was leftto the generator organisations to decide what level of reserve margin was needed to make new generationplant commercially viable.

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A value of 15% reserve margin was suggested by some respondents but most participants felt that thecompetitive market would ensure adequate reserve margin. Unfortunately this has not proved to be thecase in some other countries with competitive energy markets.

The position in New Zealand is similar with no specific reserve margin.

There is great reluctance in either country to predict beyond ten years in a competitive market situationand the figures beyond 2007 have been generally extrapolated at the same rate as the preceding few yearsexcept where comment to the contrary was provided.

The data used in developing these various predictions were not on identical bases but the differences werenot considered large enough to alter the predictions significantly. A further study on this may be warrantedto provide information to convince organisations preparing forecasts to use uniform methods.

It has been suggested that the load forecasts should be in keeping with the IEA World Energy Outlookdocument “Capacity Constraint “ case. This case has the following assumptions: it combines baseline GDPand population assumptions with rising energy prices and historical trends in energy efficiency. InAustralia and New Zealand energy prices are and certainly will continue to fall for some time. Thisincompatibility could not be reconciled in the time available but should be noted when comparisons aremade and this document is integrated with those from other economies.

4. ENERGY GENERATION MIX

In a centrally planned economy it is possible to develop a strategic energy mix for a country or region fora considerable time into the future. This may well be based on indigenous energy sources and balance ofpayment implications for imported fuels in addition to the needs of the power system for stable operation.Government in these cases has control over the form of new power generation and can modify this if a newstrategy is developed.

For many years the power industry in Australia and New Zealand was run by, or strongly influenced by,the government in office. Under these conditions government planners decided well in advance the newgeneration requirements, including the capacity of the plant and the type of technology to be used basedon perceived strategic energy mix considerations. These plans were sometimes public documents andserved as a guide for manufacturers to anticipate new plant needs.

With the advent of a competitive market situation this arrangement has changed. The government nolonger has significant control over the type of technology to be used in new plant. As a consequence ofthis, it is not able to influence the country’s strategic energy mix except perhaps indirectly by initiatingnew taxes and/or setting new environmental standards. Private investors now decide what technology isappropriate for new plant based upon economic analysis. This is highly confidential commercialinformation and is not normally available, nor is the financial analysis on which it is based or on the costsassociated with particular technologies for a specific site.

The loss in control of the strategic energy mix is of little consequence in the short term but may well havesignificant longer term implications for some countries.

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A questionnaire was prepared and circulated. Some organisations were willing to release their proposalsfor new plant while others declined, either because these were commercially sensitive or they did not havea firm view and depended on an opportunistic attitude. The information presented therefore representsfairly certain investments and is a minimum definition of new plant. In most cases the new plant waslimited to that to be installed before 2000. This information was supplemented by discussions withindustry experts knowing the available energy sources in a specific region. The results are set out belowand implications follow.

New power generation plant will certainly be built in smaller tranches to match market changes and reducemarket risk. Initially a wide variety of new energy sources will be considered, with decisions on buildingdepending much more on financial factors than technical ones.

Australia

Comments on the various sources of energy for Australia which could be used through to 2015 are set outbelow.

From the questionnaires and general society attitudes it seems unlikely that nuclear power will be used inthe period unless greenhouse requirements become much more severe.

There is no large source of water power development left which will not incur environmental problems inimplementation. As Australia is essentially a water deficient country, other forces such as humanconsumption and agriculture will take precedence over power generation in any case. Major changes towater ownership are being implemented at present by government. New generation from water over theperiod would be limited to small units.

Oil reserves in Australia are not large and the crude is light and of greater value for transport fuels thanpower generation. Transport will be willing to pay a higher price for oil than the power industry can afford.There will not be new oil fired plants except in small isolated cases. Some oil will be used as backup forgas turbines.

The major gas fields are generally located well away from centres of load and a major proportion of thegas is committed on long term contracts for export. Gas has generally been too expensive to use for powergeneration in large power stations. The development of a competitive gas market will bring the price ofgas down to a point where it may be competitive. There is at least 1,000 MW of gas available along theeast coast which could feed into power stations supplying the National Grid and 500 MW on the westcoast. Expansion of gas beyond this depends on new sources in the south eastern region or major pipelinesfrom the north west coast resources.

Coal bed methane is a source of energy which is receiving considerable attention as there are potentiallylarge reserves near load centres. Utilisation would also improve safety for underground mining. This couldwell provide an extra source of gas for the National Grid in the medium term.

Coal is plentiful and relatively cheap. Present power generation from predominantly coal fired powerstations is in the low cost generation group in the world. Competition is driving this even lower. Coal doesnot have competing industries driving the price up or limiting demand. Coal does however producesignificant greenhouse emissions and this may limit its use. New technologies are reducing the greenhouseeffect of coal by increasing plant efficiencies to a significant extent. These new technologies are availablein relatively small power plant capacities and could well be adopted for smaller increments of load.

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Renewable technologies are competitive now in remote areas. The competitive energy market willeliminate the considerable customer cross subsidisation effects present now and this will rapidly makecertain renewable energy sources such as solar and wind competitive over a much wider area as localpower prices rise after losing the cross subsidies. This is not, however, expected to constitute a largeamount of energy until large renewable energy units become available with an adequate return on investment.

Taking these implications into account, together with the comments from the questionnaire, it would appearthat new generation for some time will be gas, provided that it can be delivered at a competitive price. Thiscould well provide 1,000 to 2,000 MW into the national grid in the short term. Failing the development offurther large supplies of competitively priced gas, it would seem that additional energy requirements will bemet in the main by coal fired plant. This plant will be introduced in relatively small capacities. Present newcoal technology demonstration plants are of adequate capacity for this application and will minimiseresistance to these on environmental grounds.

New Zealand

Comments on the various sources of energy for New Zealand which could be used through to 2015 are setout below.

From the questionnaire and discussion with staff, it is extremely unlikely that New Zealand will installnuclear power stations.

New Zealand has a broad range of indigenous energy resources and new generation will come from thesesources.

It has adequate water resources without severe environmental limitations for power generation.

Gas is available with some limitations.

Research on underground gasification of lower grade coal may provide a method of utilising coal as a sourceof gas for generation in the longer term.

Geothermal and waste combustion for energy are also resources for smaller units.

Question 5 on energy mix

The present energy mix in Australia and New Zealand is set out below:

Table 6Energy mix 1995

Australia, New Zealand,% %

Coal 84 1

Water, hydro 3 70

Gas 11 22

Oil 2

Renewable, including geothermal 7

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The competitive market situation has made the prediction of the future energy mix dependent upon thechoice of many potential generators and their decisions on when to enter the market and with whatcapacity. This is sensitive commercial information and was generally not available. However mostorganisations would comment on likely short time frame probabilities. These are set out below. It must beemphasised that these predictions are for particular regions within Australia and New Zealand andrepresent best available opinions, not commitments to proceed. They do not necessarily match to realrequirements.

Table 7Likely New Generation Plant, Australia MW

2000 2005 2010 2015

Coal 800(820R) 1400

Water, hydro

Gas 1900 3500(120R) 500(120R) 850

Gas or coal, uncommitted 1000 1000

Renewable, all 100 500 2000 3000

R, retrofit older plant

By way of explanation, most existing and prospective generators are committed to gas in the short term.It is generally hoped that the introduction of a deregulated gas market in the near future will reduce theprice of gas to a more competitive level. There is at least 1000 MW of gas available on the east coast and500 MW on the west coast, which is confidently expected to be utilised by 2000. These units will beneeded for peaking but will find a suitable niche in the overall market structure, depending mainly on thecompetitive price of gas.

Sourcing gas beyond the year 2000 is more difficult and it is possible that different utilities are viewingthe same gas resource as potentially “theirs”. Again this position will be clarified with gas marketderegulation and subsequent competition. A number of utilities saw the future as gas, if available and coalif not, which can be seen in some entries for gas or coal, uncommitted.

With respect to renewables, one state passed a law last year setting an annually reducing cap on thequantity of carbon dioxide which could be sold as electricity in their territory by every individualdistributor. This was aimed at encouraging demand side management which would count as negativecarbon dioxide. As a result of this, distributors have promoted demand side management, linked with gascogeneration plants and promoted solar and wind in order to minimise carbon dioxide content in theirpower supply. In essence they have to compete for the purchase of energy on the grid but keep their overallpurchase of equivalent carbon dioxide below a cap value which is reducing annually.

In addition, one utility has invested heavily in solar energy in an attempt to reduce the cost of solarcollectors to $1 per watt before the year 2000 in anticipation of dual competitive and carbon dioxidetargets.

These predictions will distort the ABARE predictions of energy sources for generation in Table 7,increasing the gas proportion and decreasing the others in the short term.

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Table 8Energy Sources for Generation, %

1995 2000 2005 2010

Coal 84 85 84 82

Oil 2 1 1 1

Gas 11 11 11 13

Water, hydro 3 3 3 3

These new plant installations would change the energy mix in both countries toward increasing the proportionof gas in the short term, with a return to coal by 2005 if renewable technology has not been able to providelarge economically competitive amounts of energy in the intervening period.

Beyond 2010, coal will be used if competitive gas is not available and renewable units of large capacity havenot been developed. This is the general consensus of organisations which were reviewing future generationbut were not committed, even in the short to medium term, to specific new generation.

Table 9Likely New Generating Plant, New Zealand MW

2000 2005 2010 2015

Coal

Water, hydro (250R)

Gas 450(300R) 100

Gas or coal, uncommitted 700

Renewable 250 100

R, retrofit older plant, hydro and coal to gas.

The new generation possibilities in New Zealand are much broader than in Australia. The next units willprobably be gas with waste heat cogeneration, geothermal and wind providing their share in smaller units. Inthe longer term expansion will be gas driven. If enough competitively priced gas is not available, then newcoal technology using underground gasification to utilise local lower grade coal deposits may become viableby 2010.

5. ATTITUDE TO NEW GENERATION TECHNOLOGY

The other important issue was to determine the attitude of potential power generators to new technology ingeneral and to coal based technology in particular. The questionnaire was redrafted in such a way as to gainsome insights into the attitude of prospective generators as to the technology likely to be used and why thistechnology was preferred. This was supplemented by face to face interviews. The answers to the variousquestions are summarised and implications for coal based technology drawn.

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Question 4 on retrofitting existing plant

Answers to this question covered the period until 2000, with no organisation predicting beyond this. Thecommissioning dates of other existing plant can be used to predict approximately when refurbishment willbe necessary but not whether retrofitting new technology will take place.

Specific retrofit projects under consideration or committed for completion before 2000 in Australia includethe following:

Callide A Power Station, retrofit.

Colinsville Power Station, retrofit.

Gladstone Power Station, new instrumentation, fabric filters, modify ash plant and coal handling plant.

Swanbank Power Station, retrofit.

Specific projects under consideration for completion before 2000 in New Zealand include the following:

New Plymouth Power Station, retrofit

Meremere Power Station, retrofit

Question 6 on relative importance of determining factors for new generation plant using anytechnology or energy source

A set of factors was identified in the questionnaire and the participants requested to rate these, allocating 10for the most important down to 1 for the least important. In a few cases there were questions left unansweredmainly (explainable on the basis of insufficient experience).

Responses

Factor identification 1 2 3 4 5 6 7 8 9 Rating %

1 Access to indigenous fuel 1 3 2 8 1 1 3 1 2 22 4

2 Fuel flexibility 2 4 1 1 3 9 2 6 9 37 7

3 Security of fuel supply 3 2 7 7 2 4 9 2 1 37 7

4 Capital cost 5 8 6 5 9 3 6 8 4 54 11

5 Fuel cost 4 9 8 4 8 2 5 3 3 46 9

6 Required return on investment 10 10 10 10 7 5 10 10 10 82 17

7 Construction time 9 5 4 2 5 8 1 7 5 46 9

8 Overall plant availability 6 1 5 3 6 6 4 5 6 42 8

9 Environmental considerations 7 7 9 6 10 7 8 4 8 66 13

10 Political considerations 8 6 3 9 4 10 7 9 7 63 13

The most important factor was return on investment, which would be expected in a competitive situation.Political and environmental considerations were in the next group, demonstrating their new importance.

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Lesser factors which were still of importance were capital cost and construction time, followed by plantavailability and fuel cost.

This is an overall view and, in site specific cases, local conditions may dictate other priorities. The table givessome idea of the variety of approaches to these questions, but the primary attitudes are clear.

Question 7 on environmental factor ranking

Participants were asked to rate the sub factors within the environmental factor with 4 being the mostimportant and 1 the least.

Response


1 Carbon dioxide formation 4 2 1 3 4 4 1 4 4 27 31

2 Sulphur oxide formation 1 3 4 1 1 3 4 1 3 21 24

3 Nitrogen oxide formation 2 4 2 4 3 2 3 2 2 24 28

4 Other environmental factors 2 1 2 1 1 1 2 3 1 14 16

The most important environmental factors which needed consideration were carbon dioxide and nitrogenoxides. Sulphur oxides and other environmental factors were less important. The results of this question showthat international factors such as the greenhouse effect are considered to be as important as local factors suchas nitrogen oxides, important for proposed new gas fired plant in specific regions. The other factors were notfar behind in relative rating.

Question 8 on political factor rating

Here again sub factors to do with government were rated with 4 being the most important to 1 being the least.

Response


1 Taxes or subsidies 1 2 3 2 1 3 4 2 2 20 23

2 Government regulations 4 3 4 3 3 4 3 3 3 30 33

3 Promoting competition 3 4 1 4 4 2 1 4 4 27 30

4 Other political factors 2 1 2 1 1 1 2 1 1 12 13

In this question government regulations and promoting competition were seen as critical. With the presenttransition in the industry this is quite understandable. The other factors were far less important.

Question 9 covered new coal technology exclusively

Only those organisations contemplating coal based technologies replied to these questions.

The first part of the question referred to when these new coal technologies might be used. The answersprovided suggested that sub critical pf would continue to be used in new plant installations in Australiathrough to the year 2000. The introduction of IGCC plant was seen to start at 2005 at the earliest and to

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be preferred by 2010. AFBC and PFBC were seen to be available now for specific applications mainlyconcerned with burning high sulphur coals effectively with low environmental effects.

There was another group of responses which stated that plant efficiency was paramount and presumably theywould use new coal technology sooner if it were financially competitive.

The second part of the question concerned plant cost factors and environmental factors of importance forcoal fired plant. These are dealt with in the tables below.

Responses

Factor 1 2 3 4 5 6 7 8 9 Rating %

1 Capital cost 1 3 1 3 - 1 1 - 4 14 20

2 Return on investment 4 4 4 4 - 4 3 - 1 24 34

3 Plant availability 2 1 2 1 - 3 2 - 3 14 20

4 Environmental consideration 3 2 3 2 - 2 4 - 2 18 26

Responses

Environmental sub set factors 1 2 3 4 5 6 7 8 9 Rating %

1 Carbon dioxide formation 4 3 1 4 - 4 1 - 4 21 30

2 Sulphur oxide formation 2 2 2 2 - 3 4 - 3 18 26

3 Nitrogen oxide formation 1 4 4 3 - 2 3 - 2 19 27

4 Other environmental factors 3 1 3 1 - 1 2 - 1 12 17

From these responses it was obvious that the return on investment was the key factor above all others,it was the only question to score a unanimous result. The other factors rated much lower andapproximately equal. It is obvious that return on investment is critical in a competitive power generationindustry.

With respect to the environmental factors carbon dioxide and nitrogen oxides were of most concern withsulphur oxides and other environmental factors being somewhat less critical.

Question 10 gathered attitudes on a number of related energy issues

This consisted of a number of statements to which the participant replied yes, no, no change or did notknow. The results are self evident. It was interesting to note the consistent replies within Australia and NewZealand.

These votes on specific statements show very consistent attitudes throughout Australia and New Zealandon many important topics in the power industry. The results are self evident but will be used togetherwith other answers to fill in the picture of organisations competing for market share in a dynamicsituation.

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Response

Issue yes no no change not know

Deregulation will increase over time 6 1

Deregulation uncertainty will slow new plant 3 4

More complex financing will develop 7

Environmental requirements will increase 7

Nuclear energy may be utilised 6 1

Deregulation will favour gas over coal 7

At least one CCT is adequately proven 5 1 1

Coal will have extra environmental costs 6 1

Australia is too dependent on exported coal 3 2 2

Gas storage will be required for availability 4 3

Gas will become limited before 2015 2 4 1

Australia is too dependent on exported gas 5 2

The latter section of this question asks what would have to happen to overcome the barriers to the use of CCT.

A list of the issues raised in answer to this query is set out below:

Competition and economics issues

• When can CCT provide an acceptable return on investment?

• When will CCT achieve competitive capital cost?

• How can the lead time for this plant be reduced?

• Will this technology be competitive with gas cogeneration?

• Private power groups and their bankers were more conservative than previous utilities.

• Competitive conditions did not promote coal fired capacity of any type.

Technical issues

• When will CCT be proven for larger capacities, >500MW?

• When will CCT have proven availability?

• When will CCT be an acceptable risk for financiers?

• There is a lack of information on technical and cost factors.

• Manufacturers are not offering CCT plant, even as non conforming bids.

• There is a need for more demonstration plants.

• In some cases it was felt that no CCT was proven.

• The term CCT was not well understood in some cases.

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Environmental issues

• The environmental anti coal lobby is growing stronger.

• There are other low cost carbon dioxide mitigation technologies.

The questionnaires have provided a wealth of information, some of which was well known but some of whichneeds to be addressed by various sectors of the industry for CCT to be taken up at a rate which will permitcoal to continue to be utilised in a competitive and environmentally acceptable manner.

New Generation, recent case studies

There are three recent case studies concerning new generation plant specifications issued in Australia whichprovide useful background in understanding the situation.

In the first of these, an organisation called for tenders for a medium tranche of coal fired capacity for newgeneration. The offers were substantially for highly conservative plant which was eventually selected. Whilethe specification was fairly open, there were no non conforming offers of new coal technology.

The second concerned a call for a large tranche of new capacity. In this case there were a range of offers fordifferent capacity units using different technologies. It is believed that no new coal technologies were offeredeither in strict conformance with the tender or as a non complying offer. The offers eventually accepted wereliquid and gas fossil fired.

Large plant manufacturers cannot afford to offer bids which do not conform, but specifications are becomingfar more open and new coal technology will not succeed if manufacturers do not offer appropriate plant.

A third case involves brown coal research in Australia. Advanced drying and gasification technology is beingcombined into a demonstration plant equivalent to 10 MW of power generation in Victoria. This is believedto have the potential to bring brown coal utilisation to an efficiency of 42% in large units. This may wellbecome one of the driving forces in installing more advanced black coal technology.

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6. ACKNOWLEDGEMENTS

The preparation of this document would not have been possible without timely assistance with factsregarding the present energy situation in Australia and New Zealand and wise opinions for the future fromstaff from the following organisations.

AustaBHP PowerCRA EnergyElectricity Corporation of New ZealandElectricity Trust of South AustraliaEnergy AustraliaHerman Research LaboratoryHydro Electric Commission of TasmaniaLoy Yang PowerNational Grid Management CouncilPacific PowerPower and Water AuthorityQueensland GovernmentQueensland Transmission and Supply CorporationTransgridVictorian Power ExchangeWestern Power

It should be noted that there was a 100% response in returning questionnaires where they were issued. Fewquestions were left unanswered.

7. APPENDIX

Questionnaires,

• Load Growth,

• Energy mix and attitude to new generation capacity.

References

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INTERNATIONAL ENERGY AGENCYREGIONAL STUDIES ON EVOLUTION OF POWER GENERATION


QUESTIONNAIRE ON LOAD GROWTH

This document is confidential and only summated replies will be presented together with the names ofparticipating organisations .

1 Name of organisation:

2 Name and title of participant:

3 For your region what is the expected maximum demand and annual use of electricity at the followingyears

MW GWh

1995

2000

2005

2010

2015

4 What is the expected reserve margin for the region at the same following years.

MW

1995

2000

2005

2010

2015

5 What is the energy mix in your region at present (1995). The categories provided allow for international comparison.

MW

Coal

Nuclear

Water, hydro

Gas

Oil

Dual coal/oil

Dual gas/oil

Orimulsion

Renewable, all

Imported energy

TOTAL

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INTERNATIONAL ENERGY AGENCYREGIONAL STUDIES ON EVOLUTION OF POWER GENERATION


QUESTIONNAIRE ON ENERGY MIX AND ATTITUDE TO NEW GENERATION CAPACITY

This document is confidential and only summated replies will be presented together with the names ofparticipating organisations.1 Name of organisation:

2 Name and title of participant:

3 What is the energy mix in your region at present (1995). The categories provided allow for internationalcomparison.

MW

Coal

Nuclear

Water, hydro

Gas

Oil

Dual coal/oil

Dual gas/oil

Orimulsion

Renewable, all

Imported energy

TOTAL

4 What new capacity is proposed for the region over the period shown ?

MW

2000 2005 2010 2015

Coal

Nuclear

Water, hydro

Gas

Oil

Dual coal/oil

Dual gas/oil

Orimulsion

Renewable, all

TOTAL

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5 What retrofitting of existing plant is likely to take place within the region over the period shown ?

MW

2000 2005 2010 2015

Coal

Nuclear

Water, hydro

Gas

Oil

Dual coal/oil

Dual gas/oil

Orimulsion

Renewable, all

TOTAL

6 For any likely new capacity please rate the following determining factors in order of importance with10 being most important and 1 least important in your region.

Rank

Access to indigenous fuel

Fuel flexibility

Security of fuel supply

Capital cost

Fuel cost

Required return on investment

Construction time

Overall plant availability


Political considerations

7 Rank the environmental factors from 4 being most important to 1 least.

Rank

Carbon dioxide formation

Sulphur oxide formation

Nitrogen oxide formation

Other environmental factors

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8 Rank the political factors from 4 being most important to 1 least.

Rank

Taxes or subsidies

Government regulations

Promoting competition

Other political factors

9 If your organisation is considering coal based plant please answer the following question , if not goto question 10 .

What technology ( in MW capacity ) is more likely to be used in your new coal fired plant . If plant will beretrofitted list at the appropriate date in brackets.

1995 2000 2005 2010 2015

Pf sub critical

Pf super cr.

AFBC

PFBC

IGCC

For new coal fired plant what are the relative importance of the following factors with 4 most important and1 least.

Rank

Capital cost

Return on investment

Plant availability


For new coal fired plant what are the relative importance of environmental considerations with 4 mostimportant and 1 least .

Rank

Carbon dioxide formation

Sulphur oxide formation

Nitrogen oxide formation

Other environmental factors

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10 What is your response to the following statements ?

yes no no change not know

Deregulation will increase over time

Deregulation uncertainty will slow new plant

More complex financing will develop

Environmental requirements will increase

Nuclear energy may be utilised

Deregulation will favour gas over coal

At least one CCT is adequately proven

Coal will have extra environmental costs

Australia is too dependent on exported coal

Gas storage will be required for availability

Gas will become limited before 2015

Australia is too dependent on exported gas

11 What would have to happen to overcome the barriers to CCT ?

REFERENCES

Electricity Australia 1995, ESAA, ISSN 0 212 8393

Electricity Supply and Demand in New Zealand, ISBN 0 47701 704 5

Energy consumption and production to 2009-2010, ABARE Report 95.1, ISBN 0 642 22452 8

NGMC Statement of opportunities 1993

NGMC Electricity usage projections 1994-2006

NGMC Review of Statement of opportunities 1994

NGMC Electricity usage projections for 1995 statement of opportunities

NGMC proposed NEMMCO Regulations for the grid.

VPX Annual Planning Review 1995

VicPool Information Kit

Yearbook Australia, ABS No. 78, ISSN 0 810 8633

World Energy Outlook 1996, IEA

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Australia and New Zealand Region: Summary Matrix

Factor Comment

Expected load growth 18 GWin power generation till 2015 (GW capacity)

Rough projection of split of coal 12%; hydro 0%; nuclear 0%; natural gas 40%;growth by fuel type. (e.g. renewables 33%; uncommitted gas or coal 15%.coal, nuclear gas hydro)

Coal capacity (GW) bituminous coal 11.5 GW, brown coal and lignite 4.2 GW,installed since 1980 and type. total 15.7 GW. All plants are sub critical.

Major options other than coal available Natural gas and renewables.till 2010?

e.g. gas CCT

Are options likely to The proposed increased use of natural gas presumes thechange after 2010? availability of as yet unidentified economic gas reserves.

The proposed use of renewables presumes improvementsin costs and efficiencies.

Regional attitudes towards Australia has few air quality problems. Carbon dioxide new coal technology, e.g. was rated marginally ahead of the oxides of sulphur and capital cost and financing, nitrogen in the survey. Knowledge of CCT by some senior regional environmental executives was poor. Return on investment (primarily), trends, environmental environmental and political considerations and capital acceptability of coal costs would drive new plant decisions.

Specific present barriers to A highly competitive, deregulated business environment installing new coal technology does not promote coal fired plant of any type. Proven

CCT with units in excess of 500 MW, proven availability, financing risks and being competitive with gas were the main considerations.

Ideas for overcoming Presently CCT are not being considered as an option. these barriers CCT information needs to be disseminated in a better

manner, particularly for competitive retrofitting of otherwise stranded assets.

Other comments 1. Current thinking is driven by the fierce competition of the newly deregulated industry.

2. Legislation by the most populous state that caps carbon dioxide emissions has encouraged the consideration of non-coal fuels by a traditionally coal-based industry.

3. The removal of subsidies to consumers in remote regionshas encouraged the use of renewables in this small market.

4. The results of his survey contrast with official Australian forecasts, such as that by ABARE, that coal

will be preferred over gas and renewables until 2010.

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IV.2

STUDY ON EVOLUTION OF ENERGY-EFFICIENT

COAL-FIRED GENERATING TECHNOLOGY

ASIA-PACIFIC

Yasuo ARAI

EPDC

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INTRODUCTION

Electric Power Development Ltd. (EPDC) is investigating the deployment of Clean Coal Technologies(CCTs) in Japan. The main focus is on technologies which aim at further increasing the efficiency ofpulverised coal (PC) fired power plants.

Topics identified and investigated by EPDC include:

1. The evolution of electricity generating capacity by fuel type,

2. The extent of the diffusion of high efficiency CCTs for electricity generation,

3. The environmental impact deriving from the adoption of the newer technologies,

4. Actions undertaken in Japan by the Government and industry to promote the use of CCTs.

SOURCES OF INFORMATION

Reliable sources of information were the annual reports to the Ministry of International Trade and Industry(MITI) prepared by the 10 regional electric utilities. In particular, these reports contain data on regionaldemand and demand growth organised by fuel type.

As for the take up of CCTs, useful information was provided by both the major equipment manufacturersand the electric utilities.

CONCLUSIONS

1. At least until the beginning of the 21st century the expansion of the electricity generating capacity is,and will be, driven by the concept of diversifying the fuel mix to increase the security of supply.

Table 1 shows how the annual addition of new capacity until the year 2005 will be split amongst thevarious energy sources: hydro, coal, LNG/LPG, nuclear, oil, Orimulsion, and other gases. LNG/LPG willcontinue to have the lion’s share, with a total of 26,542 MW, followed closely by coal, with about 21,658MW. Hydro and nuclear remain a distant third and fourth with 14,607 MW and 10,088 MW respectively.

2. As for the take up of CCTs, ultra-supercritical (USC) steam cycle and pressurised fluidized bedcombustion (PFBC) will play an increasing role in new capacity additions. Table 2 shows how those twotechnologies will develop over time, and when the first-of-a-kind plant will be commissioned. However,the technologies are dubbed “candidates”, in the sense that some of the projects listed in the table havenot yet been completely finalised.

USC power plants are converging towards standard size of 1,000 MW with characteristic performancesof 250 kg/cm2, 600° C, 600°C. This is being accelerated by the research and development backed by the

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financial support of MITI. EPDC plays a major role in this technology development effort and receivesabout half the total budget allocated by MITI for USC-related R&D.

PFBC has been in the demonstration phase since 1989 with EPDC’s 70 MW Wakamatsu demonstrationplant. Confident of the technology, some Japanese electricity utilities have decided to make a major effortto scale-up PFBC plants, mainly to achieve a reduction in the plant costs. Therefore, three more PFBCplants are in the pipeline: the 350 MW Karita plant (Kyushu Electric), the 350 MW Tomato Azuma plant(Hokkaido Electric) and the 2x250 MW Osaki plant (Chugoku Electric) which is listed in Table 2 but notcompletely finalised yet.

3. Environmental regulation in Japan is becoming increasingly severe. This is mainly a consequence ofresident groups becoming increasingly aware and concerned about the environment and willing to playa role in shaping the agreements between the local authorities and the electricity utilities.

As an example, some local environmental regulations require pollutants to be within the followingranges: S0x<24 ppm (70 mg/Nm3), N0x<24 ppm (50 mg/Nm3), and particulates <10 mg/Nm3. In thiscase, the usual technology for the treatment of effluent gases and the reduction of concentration of S0xand N0x is a dry-type flue gas desulphurization (FGC) system based on scrubbing on activated char. Asfor the economics, this technology displays the same capital costs as in the conventional wet-type FGDwith added selected catalytic reactor (SCR) de-NOx system. However, operating costs differ due to theuse of activated char as the catalyst for the de-SOx and de-NOx operation.

Table 1 The new capacity to be split among various energy sources

Year 1996 1997 1998 1999 2000 1997- 2001 2002 2003 2004 2005 2001-

2000 2005

Total Total

Hydro 956 54 785 894 354 3043 895 58 2024 1822 2246 7045

Coal 219 1547 2924 0 3860 8550 1864 3494 4000 2400 1350 13108

LNG&LPG 4803 3340 3633 2070 805 14651 1987 3499 0 3400 3005 11891

Oil -757 -304 105 -504 -15 -1475 -45 -15 -213 0 19 -254

Other Gas 25 -22 0 -284 0 -281 0 0 25 0 0 25

Orimulsion 0 350 0 0 0 350 0 0 0 0 0 0

Geothermal 25 0 3 0 20 48 0 0 0 0 50 50

Nuclear 1356 2536 0 0 0 3892 825 0 0 2763 7121 10709

Table 2The candidates for the latest technology

Year of commissioning 1997 1998 1999 2000 2005

Unit scale (MW) 1000 1000 500 1050 1000

Technology represented each year USC USC p-FBC USC USC

246kg/cm2 250kg/cm2 250kg/cm2 250kg/cm2

593°C/593°C 600°C/600°C 600°C/610°C 600°C/610°C

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4. One of the measures introduced to speed up the deployment of CCTs, like FGDs and de-NOx systems,is the specially accelerated depreciation period set at 7 years instead of the usual 15 years.

Moreover, MITI often supports the financial effort for the deployment of the demonstration units. MITIfinancially backed the introduction of the first FGD at EPDC’s Takasago power station, and is alsosupporting the Japanese integrated coal gasification combined cycle (IGCC) research project. As forIGCC, MITI and the electricity utilities are convinced of the necessity to continue the R&D effort inorder to reach the demonstration phase as soon as possible. In recent years a fluidized-bed type gasifierwas developed, with a capacity in the range of 40 ton/day coal consumption, and was soon followed bythe Nakoso entrained-bed type gasifier, with a capacity of 200 ton/day. Both gasifiers were developedin a pilot phase.

However, the recent moves towards the deregulation of the electricity supply industry and the presenttrend towards cost cutting constitute new barriers to a fuller adoption of CCTs in Japan. Therefore,accounting for the cost factor and the increased competition brought about by deregulation, electricityutilities are becoming more and more conservative in their choice of new technologies, and less willingto make choices that bring them a return over the longer term.

Regional Characteristics Asia/Pacific: JAPAN

Expected load growth in power generation till 2010 101 GW (GW capacity)

Rough projection of split of growth by fuelling type nuclear 25% / coal 15% / LNG 23%eg coal, nuclear, gas, hydro hydro 20% / oil 16% / others 1%

Coal capacity (GW) installed since 1980 18 GW

Of coal capacity installed since 1980, how much SC: 17 GW(GW)is supercritical, how much other advanced coal eg PFBC, IGCC (including USC)

Major options other than coal available till 2010, Gas GTCCeg gas CCT

Nuclear

Are options likely to change after 2010 foreseen rise in select coal priceeg foreseen rise in gas price

Regional attitudes towards new coal technology capital cost cuttingeg, capital cost and financing, regional environmental regulation being more stringent, imposingtrends, environmental acceptability of coal new limitation on acceptable coal

specification

Specific present barriers to installing new coal present trend towards cost cuttingtechnology

Ideas for overcoming these barriers government subsidyencouraging market competition for these technologies

Any other comments

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APPENDIX V.

INCREASING THE EFFICIENCY OF COAL-FIRED POWER GENERATION

STATE OF THE TECHNOLOGY: REALITY AND PERCEPTIONS

INTERNATIONAL ENERGY AGENCY COAL INDUSTRY ADVISORY BOARD

Ian M. Torrens & William C. StenzelShell Coal International SEPRIL Services

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CONTENTS

EXECUTIVE SUMMARY ............................................................................................... 163

I. INTRODUCTION ............................................................................................................. 165

II. OVERALL SUMMARY OF SURVEY RESULTS ........................................................ 167

III. WORLD-WIDE EXPERIENCE IN SUPERCRITICAL COAL GENERATING TECHNOLOGY ......................................................................... 169

IV. PERFORMANCE AND RELIABILITY OF SUPERCRITICAL TECHNOLOGY ..... 172

V. COMPARISON OF SUPERCRITICAL VERSUS SUBCRITICAL METHODOLOGY 173

VI. COST COMPARISON OF SUPERCRITICAL VERSUS SUBCRITICAL PLANTS .. 176

VII. CONCLUSIONS................................................................................................................ 180

APPENDIX 1 THE IPP TELEPHONE SURVEY .................................................................. 182

APPENDIX 2 TECHNICAL INFORMATION....................................................................... 188

APPENDIX 3 POWER PLANT EFFICIENCY DEFINITIONS ........................................... 190

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In a nutshell.........

Independent power producers will build a substantial fraction of expected new coal-fired power generationin developing countries over the coming decades. To reduce perceived risk and obtain financing for theirprojects, they are currently building and plan to continue to build subcritical coal-fired plants withgenerating efficiency below 40%. Up-to-date engineering assessment leads to the conclusion thatsupercritical generating technology, capable of efficiencies of up to 45%, can produce electricity at a lowertotal cost than conventional plants. If such plants were built in Asia over the coming decades, the savingsin carbon dioxide emissions over their lifetime would be measured in billions of tons.

IPPs perceive supercritical technology as riskier and higher cost than conventional technology. The truthneeds to be confirmed by discussions with additional experienced power engineering companies. Bettercommunication among the interested parties could help to overcome the IPP perception issue, andhighlight problems that need to be tackled in order to make supercritical technologies accessible indeveloping countries, if indeed they are the economic choice. Governments working together with industrymight be able to identify creative financing arrangements which can encourage the use of more efficientpulverised clean coal technologies, while awaiting the commercialisation of advanced clean-coaltechnologies like gasification combined cycle and pressurised fluidised bed combustion.

EXECUTIVE SUMMARY

• New generating capacity required globally between 1993 and 2010 is estimated to be around 1500GW, of which some two-thirds will be outside the OECD, and some 40% in the Asian non-OECDcountries. Coal is likely to account for a substantial fraction of this new generation, and withliberalisation of electric power markets driven by the need for inward investment, independent powerproducers are likely to build a substantial number of the coal-fired power plants in developingcountries.

• Today’s state-of-the-art supercritical coal-fired power plant has a conversion efficiency of some 42-45%, about 5 percentage points higher than that of the conventional subcritical plants which continueto be built in most projects in non-OECD countries. First-of-a-kind plants incorporating moreadvanced ultrasupercritical technological developments, with efficiencies up to 48%, are today beingbuilt in some OECD countries. If even the more commercially proven 42% efficient supercriticalplants were to be built instead of the conventional 38% subcritical ones, the amount of incrementalcarbon dioxide not released to the atmosphere over the next few decades as a result of electricitygeneration would be measured in the billions of tons, without constraints on energy and economicgrowth. Depending on the generating efficiencies achieved, the CO2 emission reductions over thelifetime of the plants built during one decade of growth in Asia alone could amount to 5-10 billiontons.

• With more than 350 supercritical units operating world-wide today, and more than two decades ofexperience and development of this technology, their reliability today is assessed by authoritativeobservers and operators of power plants to be at least as good as that of conventional sub-criticalplants.

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• An engineering assessment by an international power engineering firm concludes that the capital costincrease associated with a supercritical or ultra-supercritical pulverised coal power plant compared toa conventional subcritical plant is small to negligible. The reason is that capital cost increases specificto the supercritical plant (e.g. associated with superior materials and other design features) arecounter-balanced by the capital cost savings associated with the fact that the boiler and ancillaryequipment can be smaller due to the increased efficiency.

• With lower fuel and operating costs, the increased efficiency associated with the supercritical plantleads to an actual reduction in the total cost of electricity generated in cents/kWh, relative to aconventional plant.

• Despite this, the independent power sector continues to build subcritical plants and has no near-termplans to increase the efficiency of power plants in the projects it is developing. There is a clearperception among IPP companies that supercritical technologies are both more expensive and containmore risk than subcritical technologies. Part of the reason for this appears to be innate conservatismamong their technology suppliers and project financiers. The fact that in IPP projects they would beexpected to bear the technology risk is an incentive to propose the most proven and risk-freetechnology. Also, and certainly a factor in the technology risk, in projects in developing countrieswhich rely heavily on local content manufacturing, the technical capabilities of the country’sengineering companies may not yet lend themselves to handling supercritical componentconstruction.

• IPP companies’ decision-making is driven primarily by the issues of reliability, technology cost,government regulation, and lender attitudes or financing constraints. Generating efficiency isperceived to be of second-order importance.

• To overcome the perception barrier, two types of action are required:

(1) Development of communication among the stakeholders - governments, IPPs, majorinternational construction engineering companies and technology suppliers - to confirm the costand reliability figures for supercritical versus conventional subcritical technology; and tohighlight issues which may make decisions on supercritical technologies more difficult indeveloping countries by comparison with OECD countries.

(2) Discussion with financing entities - private banks, multilateral funding organisations, andgovernment export credit agencies - to identify the risk issues and possible creative financingincentives which would encourage the use of more efficient generating technologies and help toovercome the issues identified in (1) above specific to developing countries.

• Advanced clean coal technologies such as integrated gasification combined cycle and pressurisedfluidised bed combustion are likely to be selected for independent power projects only in very specificcircumstances, where their technology and other risks are fully covered and their incremental costsare recovered in the price of electricity. Market penetration on a wider scale is seen by the IPPs asbeing in the 2005-2010 timeframe or beyond.

• It appears that the only way to accelerate this is to complete a number of successful demonstrationswhich, in particular, show that advanced clean coal plants can be operated reliably and with superiorperformance, and specifically that their present estimated capital costs can be reduced substantiallyto a point where they are competitive with state-of-the-art pulverised coal technologies. Thesesecond- or third-of-a-kind demonstrations are likely to require financial support by governments orelectric power companies if they are to be realised.

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I. INTRODUCTION

The CIAB’s Global Climate Committee was asked by the IEA to assess the evolution of energy-efficientcoal-fired power generation in non-OECD countries. The primary market for coal over the coming decadeswill be electricity generation, especially in the newly industrialising countries of the developing world.Estimates of the amount of new generation required between 1992 and 2010 are in the region of 1500 GW,of which more than 700 GW are in the non-OECD countries (Figures 1, 2). Coal is expected to accountfor a large proportion of new electricity generation (Figure 3).

Figure 1Electricity Generation Capacity Growth (GW) 1993-2010

The global issues of sustainable development and the enhanced greenhouse effect are topics of importanceto IEA Member governments and CIAB members. Coal, as a fossil fuel with a reserve base measured incenturies rather than decades, is an important part of the global economic-energy-environment equation.It is clear that for the newly industrialising economies to sustain the major growth phase now in progress,coal must play its part as an efficient and environmentally sound source of energy.

Today’s state-of-the-art supercritical coal-fired power plant has a conversion efficiency of some 42-45%(lower heating value - LHV), about 5 percentage points higher than that of the conventional subcritical plantswhich continue to be built in most projects in non-OECD countries. Ultrasupercritical plants are being builton a first-of-a-kind basis which have generating efficiencies of up to 48%. These plants are however still inthe early deployment stage. The efficiencies cited above assume that the power plant is located in a relativelycool climate (cooling water temperature ~10°C). In a tropical climate with cooling water temperature inexcess of 30°C, the generating efficiency would be lower by about three percentage points. This does not,however, affect the relativities to any significant extent.

The main question addressed by this paper is, what would be needed to have state-of-the-art technologyaccepted for new power projects in these countries? If this were achieved, the amount of incremental

ROW

4000

3000

2000

1000

0

ROW

OECD

OECD

1993 2010

Source: IEA World Energy Outlook 1996

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carbon dioxide not released to the atmosphere over the next few decades as a result of electricitygeneration would be measured in the billions of tons, without constraints on energy and economic growth.

Figure 2Electricity output by Country/region (TWh)

1993-2010

Figure 3Primary Energy Shares in Power Generation (TWh)

1993-2010

12000

10000

8000

6000

4000

2000

0

Hydro/Other

Nuclear

Gas

Oil

Solid

Source : IEA World Energy Outlook

1993 2010

OECD FSU/CEE ROW OECD FSU/CEE ROW

12000

9000

6000

3000

Twh

FSU/CEE OECD RowFSU/CEE OECD

1993 2010

Row

Asia-Pacific

EuropeOther

L. America

S. Asia

E. Asia

China

N. America

Source : IEA World Energy Outlook 1996

TWh

TWh

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The necessary growth of electricity generation capacity in the industrialising countries will require verysubstantial inward investment. In order to attract this investment, generation of electricity is being privatisedin an increasing number of countries. The involvement of independent power producers (IPPs) in privatepower projects in a number of countries is an important part of this process.

The CIAB took a two-pronged approach to the issues related to improving generating efficiency in new coalpower generation in non-OECD countries. A consultant, SEPRIL (jointly owned by the Electric PowerResearch Institute and Sargent & Lundy), was engaged to provide an analysis of costs and other issues in thecomparison of subcritical, supercritical and ultra-supercritical pulverised coal plants in these countries. At thesame time, in order to benefit from the insights which IPPs have gathered as a result of their experience todate in private power projects and business development in newly industrialising countries, the CIABdesigned a relatively simple survey by telephone interview. The most appropriate people to respond to sucha survey were identified and the interviews carried out between April and July 1996.

The results of the IPP Survey are summarised in the next Section and a selection of responses to theindividual questions are contained in Appendix 1. The findings of the cost and performance comparativeanalysis are presented in Sections V. and VI.

II. OVERALL SUMMARY OF SURVEY RESULTS

A total of fourteen companies were interviewed by telephone and/or sent written responses to the CIABQuestionnaire. The majority of those interviewed represented independent power producing companiesinvolved in developing power projects in non-OECD countries. However, representatives of several powerengineering/construction companies and technology suppliers also participated. Appendix 1 contains a listof companies which took part in the Survey. Those who agreed to take part were assured that theanonymity of their responses would be protected, and that the results of the Survey would be shared withthem.

There was a high degree of consensus among the participants in their responses to the questions, whichmakes it relatively simple to draw broad conclusions. In Appendix 1. we reproduce a cross-section of theresponses to each of the questions. The main lessons to be drawn from the Survey are the following:

1. TECHNOLOGIES USED OR FORESEEN

The vast majority of projects use or plan to use sub-critical pulverised coal technologies for larger plants,with some smaller projects using atmospheric fluidised bed combustion (AFBC) technology. Supercriticalpulverised coal technology is viewed as technically commercialised but riskier and more costly, andneeding incentives such as high priced fuel to be the technology of choice. Pressurised fluidised bedcombustion (PFBC) and integrated coal gasification combined cycle (IGCC) technologies may be used inspecial circumstances (e.g. government support) in the coming years, but are unlikely to come intowidespread use by IPPs until 2005-2010 or beyond.

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2. ENVIRONMENTAL REQUIREMENTS

The World Bank Environmental Guidelines play a major and increasing role in most countries. Some IPPshave corporate environmental guidelines which go beyond the World Bank ones. However, to go too farbeyond raises economic competitiveness issues.

3. MAIN FACTORS INFLUENCING TECHNOLOGY SELECTION

Reliability, technology cost, and financing constraints were voted the most important factors (averaging 4.6on a scale of 1 to 5 in importance). The standard deviation in the responses was relatively small, of the orderof 0.6, indicating a strong consensus on these factors. The next most important factors were governmentregulation (4.4), maintainability (4.2), technology risk and lender attitudes (both 4.1), technology maturity(4.0), and environment (3.9). IPPs viewed environment as extremely important, but not a critical factor intechnology choice, since available generating technologies are capable of meeting or exceeding World BankEnvironmental Guidelines and national/local standards in most non-OECD countries.

Interestingly, the need for skilled operators scored relatively low in the poll (3.3), the IPP view being that it isrelatively easy to find and train operators. The full results of the poll on factors influencing technology selectionare shown in the response to Questions 3 and 4, summarised in Table 1 of Appendix 1.

4. POWER PLANT CONVERSION EFFICIENCIES

Most coal-fired power plants being planned or built today use sub-critical technology and have conversionefficiencies in the range of 37-39% on a lower heating value (LHV) basis (9200-8700 Btu/kWh). Appendix3 contains a brief explanation of efficiency and its relationship with heating value, which can sometimes bea source of confusion.

Responses on future trends in efficiency over the next 5-10 years were mixed, though few expect increasesof more than a few percentage points.

5. WHAT IT WOULD TAKE TO IMPROVE GENERATING EFFICIENCIES

The present relatively low cost of fuel in non-OECD countries is perceived to be a disincentive to achievingsignificant increases in generating efficiency. Only when fuel is expensive will competitive pressures bythemselves lead to efficiency improvements. Stricter environmental requirements could play a role(especially constraints on carbon dioxide emissions). Governments can mandate efficiency standards, but thisis not seen as likely unless there is a strong national or international reason for doing so.

There is a common perception of higher capital and operating cost, and risk of reduced plant operatingreliability, associated with supercritical pulverised coal technologies, both among IPPs themselves and,perhaps more important, among their engineering and technology supply partners. The latter are normallyexpected to bear the technology risk in an IPP project, which tends to bias them towards conservatism.Some of the higher cost may also in fact be due to the higher perceived risk premia in project-financed IPPplants. There may be an information gap here that could be bridged by further dialogue.

The responses to the IPP Survey have highlighted a perception that supercritical pulverised coal technologyis both costlier and riskier than conventional subcritical technology. How justified is that perception? Theother part of this assessment, described below in Sections V. and VI., attempts to respond to this question.

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III. WORLD-WIDE EXPERIENCE IN SUPERCRITICAL COALGENERATING TECHNOLOGY

Pulverised coal plant fuel efficiency improvements and air emissions reductions are achieved with highercycle operating pressures and temperatures. The subcritical (termed “conventional” in this assessment)pressure cycle with one stage of reheating at 2400 psig/1000°F (166 bar/538°C) cycle has been the dominantdesign in the past and continues to be the most often selected cycle. The supercritical (SC) cycle at 3500psig/1000°F (240 bar/538°C) cycle has been used for a smaller number of plants and the ultra-supercritical(USC) with two stages of reheating at 4500 psig/1100°F (311 bar/593°C) is the state-of-the-art“commercially” available plant. The nominal design efficiencies based on lower heating value and at the fullload condition for these plants are: Conventional ~ 38%, SC ~ 41% and USC ~ 45%. Appendix 2.1 providesan explanation of the key technical terms.

High pressure and pressure component metallurgy, critical boiler and turbine component design, and waterchemistry are the main technical issues to address when deciding among SUB, SC and USC generatingtechnologies. Appendix 2.2 summarises major developments for critical piping and turbine components.

The major parameters for a selection of SC plants recently placed in operation, currently in construction,in design/development, are compared with the Eddystone plant in the United States (installed in 1958) inTable 1 below (2).

Table 1International Supercritical Generating Experience

USA Europe Japan

Eddystone Esbjergvaerket 3 (Denmark) Kawagoe 1&2(400 MW) (400 MW, 1992) (700 MW, 1990)5000 psig, (1100 °F) 3600 psig, (1145 °F) 4680 psig, (1060 °F)350 Bar (593°C) 250 bar (560°C) 325 bar (571°C)Coal Fuel Coal Fuel Gas Fuel

EPRI, Study ELSAM Konvoj 1 & 2 (Denmark) Master 2(350 MW) (400 MW, 1997/98) (1000 MW, 1997)4500 psig, (1100°F) 4175 psig, (1080 °F) 3685 psig, (1100 °F)311 bar (593°C) 290 bar (580°C) 256 bar (593°C)Coal Fuel Coal/Gas Fuel Coal Fuel

Lübeck 1 (Germany) Study(400 MW, 1995) 4680 psig, (1100 °F)3960 psig, (1080 °F) 325 bar (593°C)275 bar (580°C)Coal Fuel

The Philadelphia Electric Company’s Eddystone Plant, which was placed into operation in 1958, hassignificantly better efficiency than any plant of that era. The design efficiency of this plant was 43% (LHV)based on the original steam conditions and 41% (LHV) based on the plant’s re-rated conditions. The plantdesign and its continued normal operation are an impressive accomplishment.

The SOAPP (State-or-the-Art Power Plant) USC plant design has been developed by Electric PowerResearch Institute (EPRI), Sargent & Lundy and SEPRIL Services. This design has a cycle efficiency of

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~44%, (LHV) based on turbine inlet steam conditions of 4500 psig and 1100°F (311 bar and 593°C), andfirst and second reheat at 1100°F (593°C), and a higher quality U.S. fuel. This plant utilises commerciallyavailable equipment and materials and can be configured with a variety of emission and water dischargetechnologies. SEPRIL is continuing to develop performance, design, and costs. In addition, SEPRIL iscontinuing to develop the SOAPP software for plant evaluations, and optimisation.

1. SUPERCRITICAL INSTALLATIONS IN THE UNITED STATES

Table 2 provides a list of operating plants in the United States with advanced cycle conditions (SC and oneUSC) and two stages of steam reheating:

Table 2 Existing advanced cycles at u.s. utility installations

Main Steam First Reheat Second ReheatUnit and Utility Pressure Temperature Temperature Temperature Design

Bar (°C) (°C) (°C) Capacity(psig) (°F) (°F) (°F) MW

Eddystone 1 10 343 649 565 565 325ECO (5,000) (1,200) (1,050) (1,050)

Breed 1, AEP 240 565 565 565 450(3,500) (1,050) (1,050) (1,050)

Sporn 5, AEP 240 565 565 565 450(3,500) (1,050) (1,050) (1,050)

Eddystone 2, PECO 240 565 565 565 325(3,500) (1,050) (1,050) (1,050)

Tanners Creek 4, AEP 240 538 552 565 580(3,500) (1,000) (1,025) (1,050)

Muskingum River 5, AEP 240 538 552 565 590(3,500) (1,000) (1,025) (1,050)

Cardinal 1 & 2, AEP 240 538 552 565 600(3,500) (1,000) (1,025) (1,050)

Hudson 1, PSE&G 240 538 552 565 400(3,500) (1,000) (1,025) (1,050)

Brayton Point 3, NEP 240 538 552 565 600(3,500) (1,000) (1,025) (1,050)

Hudson 2, PSE&G 240 538 552 565 600(3,500) (1,000) (1,025) (1,050)

Big Sandy 2, AEP 240 538 552 565 760(3,500) (1,000) (1,025) (1,050)

Chalk Point 1 & 2, PEPCO 240 538 552 565 355(3,500) (1,000) (1,050) (1,000)

Haynes 5 & 6, L.A. 240 538 552 565 330(3,500) (1,000) (1,025) (1,050)

Mitchell 1 & 2, AEP 240 538 552 565 760(3,500) (1,000) (1,025) (1,050)

Amos 1 & 2, AEP 240 538 552 565 760(3,500) (1,000) (1,025) (1,050)

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2. WORLD WIDE EXPERIENCE IN SUPERCRITICAL GENERATING PLANTS

The greatest concentration of installed supercritical plants is in the former Soviet Union countries where232 units are in operation. These units are designed at specific sizes: 300 MW, 500 MW, 800 MW, 1200 MW,and have steam conditions typically 234 Bar/565°C/565°C, with some advanced designs operating at292 Bar/649°C/649°C. EPRI has studied and reported on these plants (1).

Figure 4 (7) shows a plot of the SC plants (1980 to 2000) installed and planned in Europe and Japan.Supercritical plant sizes ranges from 325 MW to 1000 MW with the mean tending to increase. A 600 MWplant falls about in the middle of the pack. In Japan, 50-60 supercritical units are in operation or plannedat steam pressures up to 309 Bar and temperatures to 594°C. They include landmark units at the gas-firedChubu Electric, Kawagoe 700 MW units (309 Bar/566°C/566°C/566°C), coal-fired Hekinan #3, 700 MWunit with main steam and reheat temperatures of 538°C/593°C, and Matsuura #2, 1000 MW plant withsteam conditions of 240 Bar/593°C/593°C, to be in operation in 1997. There are 31 coal-fired supercriticalunits in Europe, of which 16 in Germany and 8 in Denmark: 6 more units are under construction(8).Operating plants include two advanced coal-fired units in Denmark: Esbjerg #3, with steam conditions of245 Bar/560°C/560°C, and Nordjyllandsvaerket (Aalborg), a 400 MW plant with steam conditions of290 Bar/580°C/580°C, to be in operation in 1998. A 300 Bar 580°C/600°C plant has been ordered to comeinto operation soon after the year 2000.

Figure 4Sizes of Supercritical Coal Generating Plants in Europe and Japan

Pla

nt S

ize

(MW

)

1200

1000

800

600

400

200

1980 1985 1990 1995 2000

Year

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IV. PERFORMANCE AND RELIABILITY OF SUPERCRITICAL TECHNOLOGY

1. RELIABILITY/OPERATION

Experience with the higher temperatures and pressures involved in supercritical technology has grownsubstantially over the past two decades, and earlier technical problems have been to a large extent overcomeby improvements in materials and design. There remain some corrosion problems stemming from the highertemperatures, which makes supercritical less suitable for high slagging or corrosion coals. Coal with greaterthan about 2% sulphur has caused some superheater and reheater difficulties. However, these difficulties arenot necessarily specifically related to the sulphur content - coal chlorine and other constituents can have amajor impact on the corrosion rates.

There are options which boiler manufacturers can employ with more corrosive coals to mitigate theseproblems. Boiler design optimisation options include a larger furnace for lower gas temperatures enteringthe reheater and superheater, use of higher alloy materials which have recently become available, tubeshields, a tube cooling screen before the superheater and reheater, boiler water and steam circuitry toreduce high gas temperatures because of uneven gas and steam/water exchange in the combustion andother heat transfer zones, and other means.

Boiler tube leaks are a major issue for plant operation, often being the cause of loss of reliability. There isoccasionally a tendency to generalise the difficulties caused by tube leakage problems, e.g. water wallleaks are not differentiated from superheater and reheater problems. However, tube leaks are often causedby water chemistry problems and not directly related to the coal quality. Many units have switched to theuse of oxygenated water treatment instead of using all volatile or co-ordinated phosphate treatment for theboiler-turbine water/steam cycle. This improvement has proven to reduce tube leaks very substantially.

Studies made by EPRI on relative reliability of coal-fired sub- and supercritical plants in the UnitedStates(1), show that the conventional units have in the past had better reliability during the first ten yearsof operation, but by the time a supercritical unit was ten years old, the average outage hours caused by thepressure parts of the supercritical unit had levelled off at less than 500 hours/year (approximately 6%/yearavailability) for all U.S. units, while for subcritical units the level was the same but climbing.

Study of the outage data shows that the main cause of these outages were related to the temperature effects,to boiler tube thermal fatigue and creep stresses in headers, steamlines and in turbines forgings andcastings due to long-term overheating. EPRI research showed that such issues can be overcome by the useof high chrome materials for superheater and reheater tubing, and by the use of super 9-chrome steel (P91)for high temperature headers, steam lines, valves, and turbine components. This 9-chrome steel, a verystrong ferritic material, developed in the U.S. as part of the breeder reactor programme and endorsed byEPRI for fossil power plants, is now routinely used.

Other aspects of supercritical plant operation, identified in EPRI’s evaluation of early supercritical unitsas requiring attention, included the design of start-up systems and potential adverse effects on valving,solid particle erosion of turbine blades, and waterwall tube cracking. All these issues have now beenovercome(6, 8, 9) and no longer represent barriers to the use of supercritical steam conditions.

The result of the metallurgy, equipment design and water treatment improvements leads to the reasonableexpectation that a new supercritical unit will today operate as reliably as a conventional unit.

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Operating personnel needed for the SC and USC plants may not be readily available in the country wherethe plant is being installed. However, this problem can be readily handled by hiring operating staff earlierin the project schedule for intensive training, by supervision by experienced plant engineers, and by theuse of simulators.

It is possible that commercial risks for a supercritical plant burning greater than 2% sulphur coal might besubject to greater premiums owing to less historical experience. However, many of the plants to be built inAsia over the coming decades will use relatively low sulphur coal, so this issue may be only be encounteredfor plants attached to some specifically higher sulphur reserves.

2. CONSTRUCTION

The critical components of the SUB and SC plant require materials that are frequently not available insome countries. However, during the development of most projects there are detailed investigations of thenearby manufacturing capabilities and effective plans can be developed for local supply and manufacturingwhere feasible. Materials and fabrication equipment which cannot be manufactured locally are readilyavailable from other countries. Spare parts, materials and components are usually provided during theinitial plant construction phase. Special construction personnel for high temperature and pressure materialsmay be required, and may need to be at the site for large parts of the construction schedule.

3. OPERATING PERFORMANCE GUARANTEES

Most plants and equipment are purchased with efficiency and reliability guarantees, which are importantfeatures of the bidding or negotiation process for the plant. The guarantees have associated bonus/penaltiesand liquidated damages placing the proper emphasis on the construction contractor and equipment supplierto meet the quoted performance level.

In summary, early problems in first and second generation supercritical boilers and steam turbines havebeen overcome. Experience over the past decade shows that the reliability and availability of thesupercritical cycle after more than 30 years of research and development can match or better the subcriticalcycle for base loaded operation.

V. COMPARISON OF SUPERCRITICAL VERSUS SUBCRITICAL PLANT PERFORMANCE

In order to assess the cost-effectiveness and environmental performance of SC and USC coal-firedgenerating plants versus a “conventional” subcritical plant of the type used in most IPP projects today, ananalysis of comparative performance and cost was carried out using the SOAPP data-base, for a 600 MWPC-fired plant in an Asian location. For this case study, the following scenarios were evaluated:

(1) 2400 psig subcritical plant with an electrostatic precipitator for particulate control and low-NOx burners,but no post-combustion sulphur or nitrogen oxide controls (Conventional Plant).

(2) 3500 psig supercritical plant (SC).

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(3) 4500 psig ultra supercritical plant (USC).

(4) 4500 psig ultra supercritical plant with spray dryer FGD, SCR, and baghouse for particulate control(USC w/FGD, SCR).

The analysis was carried out for two variants of capital cost (engineering, procurement and construction) andfor two types of coal. The higher level of capital cost (~$800/kW for a subcritical plant without FGD)corresponds to that for a plant built in an OECD country, and the lower capital cost (~$620/kW) to that for asimilar plant constructed in a developing country such as China. The lower priced coal (~$15/short ton,heating value 7900 Btu/lb) might be that for a minemouth coal plant, and the higher coal price (~$40/shortton, heating value 12000 Btu/lb) might be the landed price of internationally traded coal at a coastal powerplant.

1. PLANT EFFICIENCY

The plant efficiency comparison is shown in the Figure 5. Compared to the conventional subcritical plant’s 38%efficiency, a supercritical plant can readily achieve 41% and an ultra-supercritical one 45% on an LHV basis.These are quite conservative figures for the ultra-supercritical plant, and are intended to represent the generationof USCPF which is offered commercially today. Also, it would be possible for a subcritical plant to achievegreater efficiency via higher temperatures (up to about 40%). The “conventional” plant in this comparison,however, is intended to represent one typical of many IPP coal plants currently in operation, construction, orproject development.

Figure 5Plant Efficiencies (LVH). Supercritical Versus Subcritical

2. FUEL CONSUMPTION

The plant efficiency improvements result in significant reduction in fuel consumption. A 600 MWconventional plant has a primary fuel feed rate (100% load) of ~ 750,000 lb/hr. The more efficient USC planthas a primary fuel feed rate of 645,000 lb/hr. This translates to over ~375,000 short tons/year of coal notcombusted, which results in a fuel cost savings of approximately $6 million/year for a USC plant vs. aconventional plant based on a fuel cost of $15 per ton delivered (calorific value 7900 Btu/lb), orapproximately $10 million/year if the fuel cost is $40/ton (calorific value 12000 Btu/lb).

Conventional SC USC

46%

44%

42%

40%

38%

36%

34%

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3. CO2 EMISSIONS

With the recent attention focused on the international greenhouse issue, emissions of CO2 from coal-firedpower plants have received increasing attention. The annual mass CO2 emissions for the conventional, SCand USC plants are ~5.2 million short tons, 4.8 million tons and 4.4 million tons respectively (Figure 6). Thisrepresents an 8% emission reduction for the SC and 15% for the USC plant relative to the conventionalsubcritical technology. Consequently, even the intermediate step of the supercritical plant reduces CO2emissions by almost a half million tons per annum for a 600 MW plant, or 0.7 million tons/GW. Over the 40year lifetime of 1 GW of new coal generation, 28 million tons less CO2 would be emitted. Asia alone mayneed to construct 15 GW per year of new coal generation over the next two decades, according to the IEA’sWorld Energy Outlook (10). Thus one year’s incremental generation would produce 420 million tons lessCO2 during its lifetime, and the savings from one decade of this growth would amount to almost 5 billiontons of CO2. And going to ultra-supercritical plants would double this. The stakes are clearly rather high.

Figure 6

Carbon Dioxide Emissions (Million Tons/year, 600 MW Unit)

Figure 7

SO2 & NOx Emissions (1000 tons/year, 600 MW Unit)

25

20

15

10

5

0Conventional SC

SO2

NOx

USC USC w/FGD/SCRBaghouse

Conventional SC USC

5.4

5.2

5.0

4.8

4.6

4.4

4.2

4.0

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4. SO2 AND NOx EMISSIONS

Emissions of gaseous pollutants are also reduced by building more efficient plants. The emission controlequipment required for a plant depends on the coal selected and the applicable emission regulations.Currently, most plants in Asia are being installed with low NOx boiler burner equipment, but only a fewhave FGD Systems. This approach is based on the use of low sulphur coal, the cost, and current nationalair emission regulations or World Bank environmental guidelines. Emissions of both conventionalpollutants (SO2, NOx, particulate, etc.) and carbon dioxide are lower for the more efficient supercriticalplants than for the traditional subcritical plant. When comparing plants without post-combustion airpollution controls, mass emissions of SO2 are reduced by 3300 tons/year, and emissions of NOx by 1180tons/year for a USC plant compared to a conventional plant (Figure 7).

With the use of state-of-the-art air pollution controls, emissions of conventional pollutants can be reducedto ultra-low levels. The USC plant equipped with a lime spray dryer, SCR, and baghouse can produceemissions of 0.11 lb/MBtu SO2, 0.06 lb/MBtu NOx, and 0.005 lb/MBtu particulate. The additional capitalcost for this system on a 600 MW unit with low sulphur coal fuel (<.9%) would be approximately$130/kW. This cost increment is relatively low because the spray-dryer/baghouse combination issubstituted for the precipitator included in the other cases. The emissions could be reduced by up to ~90%with this sulphur content coal. This low emissions boiler would be able to satisfy the most stringentregulatory requirements.

VI. COST COMPARISON OF SUPERCRITICAL VERSUS SUBCRITICAL PLANTS

The capital costs differences (higher capital cost case) are shown in Table 3, which also separates out themain items for which the cost increases in the supercritical and ultra-supercritical plants relative to theconventional plant.

The plant would have two units with low NOx burners, high efficiency particulate collection equipment,once through sea water cooling, including the switch yard and all the facilities for a new site location, anda 60 month construction schedule. The capital costs in Table 3 include the plant equipment, structures,switchyard, and coal unloading facilities.

The increases in cost for the higher pressure cycles plants are not as high as was evident in previousevaluations performed several years ago, because of better materials, equipment designs and othertechnological knowledge, and growing experience with the higher pressure and temperature cycles.Another factor is the beneficial impact of the higher efficiency cycle on the overall plant costs, in the formof reduced costs for smaller coal handling systems, precipitators, and cooling systems, etc. These costreductions offset the increased costs for the higher pressure and temperature cycle boiler, turbine, piping,pump, feedwater heater, etc. equipment. This is shown graphically in Figure 8.

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Table 3Capital Costs of Supercritical versus Subcritical Generating Plants

$/kW Subcritical Supercritical Ultra- Ultra-Supercritical Supercritical with FGD System

& SCR

Boiler (incl.steel, air heater, etc.) $142.94 $153.09 $163.52 $163.52% compared to base Base 107.1% 114.4% 114.4%

Boiler plant piping $27.81 $31.03 $31.81 $31.81% compared to base Base 111.6% 114.4% 114.4%

Feedwater systems 28.06 $28.62 $29.18 $29.18`% compared to base Base 102.0% 104.0% 104.0%

Turbine-Generator $79.20 $82.37 $83.95 $83.95% compared to base Base 104.0% 106.0% 106.0%

Turbine plant piping $16.25 $15.44 $15.43 $15.43% compared to base Base 95.0% 95.0% 95.0%

Subtotal for boiler, turbine, high $294.26 $310.38 $323.91 $323.91 pressure piping, feedwater systems

% compared to base Base 105.5% 110.1% 110.1%

Remainder of Plant $509.17 $500.69 $487.17 $604.76

% compared to base Base 98.3% 95.7% 118.8%

Total Plant Cost $803.43 $811.07 $811.08 $928.67 % compared to base Base 101.0% 101.0% 115.6%

Figure 8Capital Cost Comparison for 2x600 MW Coal Fired Power plant

Higher Capital Cost Case

Equipment with Cost Increase

Remainder of Plant

1000

900

800

700

600

500

300

200

100

0

400

Conventional SC USC USC w/FGD/SCRBaghouse

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It is of course a valid question as to whether the substantial cost savings realised during recent years insubcritical plant design and construction may not be easily translated to supercritical and ultrasupercriticaldesigns. While it is unlikely that plant designs for supercritical have reached the same “off-the-shelf”sophistication which the construction engineering firms now offer for subcritical plants, there is no a priorireason why the same competitive forces which led to these offerings should not come into play as soon asthere is a demand for cost-effective supercritical plants. There may be some delays as the engineeringcompanies organise themselves to provide the equipment at lowest possible cost and make possible themaximum degree of economic local content of power plants constructed in developing countries.

Table 4 summarises the economic parameters used to calculate the cost of electricity generated from thedifferent types of plant.

Table 4

Plant Operating Period = 30 Years Fuel Cost A = $15.20/ton, B = $40/ton

Plant Operating Hours = ~ 85% availability Interest during construction = 9.8%

Capacity Factor = ~80% O&M Escalation 2%

Fixed Charge Rate = 13% $5/ton Waste Disposal Costs

O&M (fixed) = ~ $13/kW-year

Capital charges and fixed O&M are higher for the SC and USC cycles, while total fuel costs are lower forthe SC and USC because of the higher efficiencies. The O&M cost estimate was developed using the methodsand data typically used for economic comparisons for new projects. The average availability for all threepulverised coal generating cycles included in this study is 85% and the capacity factor for all the units is 80%.This target is based on data from existing plants.

The results are shown in Figure 9(a) and (b) for the lower coal price and Figure 10(a) and (b) for the highercoal price. In each of these Figures, (a) is the higher capital cost case and (b) the lower capital cost case. Asexpected, the effect of fuel price is very significant. When the higher level of capital cost is used in theanalysis, going from conventional to supercritical in the lower coal price case reduces the electricity cost by0.08 cents/kWh, and in the higher coal price case by 0.23 cents/kWh - almost a factor of three. Thecorresponding reductions in going from conventional to ultrasupercritical are 0.14 cents/kWh in the lowercoal price case and 0.48 cents/kWh in the higher coal price case. Figure 10 shows that an ultrasupercriticalplant with state-of-the-art sulphur and nitrogen oxide controls and a high efficiency baghouse for particulatecontrol can produce cheaper electricity than a conventional plant with only a precipitator for particulatecontrol!

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Figure 9 (a)Cost of Electricity (cents/kWh)

Lower Fuel Cost ($15/short ton)/Higher Capital Cost Case

Figure 9 (b)Cost of Electricity (cents/kWh)

Lower Fuel Cost ($15/short ton)/Lower Capital Cost Case

Figure 10 (a)Cost of Electricity (cents/kWh)

Higher Fuel Cost ($40/short ton)/Higher Capital Cost Case

Conventional SC USC USC w/FGD/SCR+ Baghouse

Fuel Costs

Variable O&M

Fixed O&M

Capital Charges

7.0

6.0

5.0

4.0

3.0

2.0

1.0

0


Fuel Costs

Variable O&M

Fixed O&M

Capital Charges

6.0

5.0

4.0

3.0

2.0

1.0

0


5.0

4.0

3.0

2.0

1.0

0

Fuel Costs

Variable O&M

Fixed O&M

Capital Charges

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Figure 10 (b)Cost of Electricity (cents/kWh)

Higher Fuel Cost ($40/short ton)/Lower Capital Cost Case

When the lower capital cost is used in the analysis, the corresponding reductions in going fromconventional to ultrasupercritical are 0.15 cents/kWh in the lower coal price case and 0.46 cents/kWh inthe higher coal price case, implying that the choice of whether to use subcritical or supercriticaltechnologies is not very sensitive to general capital cost levels.

VII. CONCLUSIONS

The independent power sector has been and remains reluctant to employ advanced clean coal technologiesfor power generation projects. The current standard appears to be a subcritical pulverised coal plant with fluegas clean-up adequate to meet World Bank Environmental Guidelines. Only minor improvements ingenerating efficiency are expected by the IPP sector over the next 5 years. Advanced clean coal technologieslike PFBC and IGCC are expected to be selected only in special cases where their risks are fully covered andincremental costs recovered in the price of electricity produced. Their market penetration on a wider scale isseen by the IPPs as being in the 2005-2010 timeframe or beyond. It appears that the only way to acceleratethis is to complete a number of successful demonstrations which, in particular, show that advanced clean coalplants can be operated reliably and with superior performance, and specifically that their present estimatedcapital costs can be reduced substantially to a point where they are competitive with state-of-the-artpulverised coal technologies.

Supercritical pulverised coal technology is perceived as available but more costly and containing addedrisk in terms of reliability. Also, there are few incentives to employ it in non-OECD countries, especiallywhere coal is inexpensive. In addition to a lack of any incentives, there appears to be a perception problem,possibly due to lack of information, which may need to be addressed by the IEA and others, if theadvantages of supercritical generating efficiency improvements, both environmental and economic, are to


Fuel Costs

Variable O&M

Fixed O&M

Capital Charges

7.0

6.0

5.0

4.0

3.0

2.0

1.0

0

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be realised in the near future. Significant cost advantages, especially for higher fuel cost but still significantfor lower cost fuel, have been confirmed by an economic analysis of subcritical versus supercritical state-of-the-art pulverised coal power plants carried out for the CIAB by SEPRIL.

An important step in addressing the issue of higher efficiency coal generation is to solicit the views of theprincipal power plant engineering companies and technology suppliers, with special attention to the expectedreliability and the relative economics of supercritical versus subcritical plants. The IEA may wish to take upthe question of possible incentives for use of more efficient plants with its intergovernmental committeessuch as the Standing Group on Long Term Co-operation and the Committee on Energy Research andTechnology’s Fossil Fuel Working Party. The IEA Energy Seminar in Beijing in December 1996 provided atimely opportunity to present this information to the government of an important country for future electricpower growth, and the Chinese government has indicated its interest in supercritical technology in solicitingtenders for coal-fired generation in the Shanghai area. Globally, the stakes are sufficiently high, in the formof reduction of future growth of carbon dioxide and other pollutant emissions, for this issue to receiveattention by both industry leaders and government policymakers in IEA/OECD countries and beyond.

REFERENCES

1. Development Plan for Advanced Fossil Fuel Power Plants, EPRI Report CS-4029, By Bilber Associates,1985.

2. Turbine Designs for Improved Coal-Fired Power Plants, EPRI Research Project 1403-15, TR-100460,by General Electric Company and Toshiba Corporation, edited by Encotech Inc., 1991.

3. The Advanced Pulverised Coal-Fired Power Plant: Status and Future, by S. Kjaer. ofELSAMPROJEKT, presented at the 1994 ASME, International Power Generation Conference (PWR-40).

4. Keynote lecture of the VGB Conference, Kolding June 93:, by S. Kjaer - Elsamprojekt, H. Koetzier andJ. van Liere - KEMA and I Rasmussen - Midkraft Power Company, Aarhus DK.

5. Newly Developed High Temperature Ferritic-Martensitic Steels from USA, Japan and Europe, by R.Blum, Faelleskemiderne, Fynsvaerket, Odense, Denmark, et,. al., presented at the 1993 International VGBConference Fossil-Fired Power Plants with Advanced Design Parameters.

6. Development of Improved Boiler Startup Valves, EPRI Report GS-6280, April 1989.

7. Particle Erosion Technology Assessment, EPRI Report TR-103552, December 1993.

8. Private Communication, A. Faurholt, SK Power Company, Denmark (1997).

9. Circumferential Cracking of the Waterwalls of Supercritical Boilers, EPRI Report TR-104442,September 1995.

10. World Energy Outlook, International Energy Agency, OECD, Paris 1996.

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APPENDIX 1

THE IPP TELEPHONE SURVEY

1. COMPANIES REPRESENTED

ABB Carbon AES Corporation

Babcock and Wilcox Black and Veatch

Community Energy Alternatives CMS Generation

Duke Energy Edison Mission Energy

Elsamprojekt Entergy Power Systems

IVO Energy International National Power

NRG Energy Southern Electric International

2. SURVEY QUESTIONS AND SUMMARY OF RESPONSES

1. Which technologies have you used for coal-fired power projects in non-OECD countries, andwhich technologies would you anticipate using a decade hence? (Examples include pulverised coalcombustion (sub-critical or super-critical), fluidised bed combustion (atmospheric orpressurised), coal gasification combined cycle).

1996

• Only sub-critical pulverised coal and AFBC

• Efficiency gain for supercritical is not worth the trouble

• Commercial technology suppliers (especially U.S. ones) are conservative and don’t push forsupercritical

• Financing not available for supercritical

• Gasification capital cost very high

• IGCC has no chance if competing with gas

• Integrated IGCC technology is not yet proven

• FBC seen as a niche opportunity - special coals and size < 200 MW.

• Might consider IGCC with other fuels like petroleum coke

• Would hesitate to apply IGCC or PFBC in a non-OECD country

• Supercritical is OK technology-wise, but be certain the full skill level is available before usingit in a non-OECD country

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2005

• Expect to see more supercritical plants

• PFBC appeals but more competition in supply is needed - only one supplier today

• Don’t expect to see IGCC until after 2010 except where favoured by a subsidy or regulatorystringency

2. What environmental, energy conversion efficiency, and reliability requirements do (or will)your projects have to meet in non-OECD countries?

For example, do the World Bank Environmental Guidelines play a role?

Are there any specific energy conversion efficiency or reliability/maintainability requirementsplaced on projects you have developed to date, by other entities (e.g. governments) oryourselves?

Environment

• World Bank standards or local standards where stricter

• Local standards only (especially in competitive bidding situation, where higher standards wouldpenalise the bid)

• Would build plants better than World Bank standards, but it is a good benchmark

• All plants meet host country standards, which are usually World Bank Standards

• World Bank standards are becoming the norm for financing, as risk mitigation

• Definitely subject to World Bank standards, but also we have internal corporate environmentalstandards

• Would go beyond World Bank standards if additional enhancement possible while protectingcompetitive position

• Need to anticipate future tightening of standards for existing plants

• Spending money on better sanitation is more important for many non-OECD countries than on98% sulphur removal.

Efficiency

• Not considered important by non-OECD governments

• Efficiency interacts with fuel cost in overall economic optimisation

• Economic optimisation, especially where coal is cheap, does not favour higher efficiency plants

• Driven by economics - do what it takes to compete

• No specific efficiency or reliability/maintainability requirements - these are part of determiningthe lowest cost long-term power option

• Typically governments/government utilities are biased against higher efficiency supercriticalplants

• For coal plants > 10,000 Btu/kWh (34%) is probably not optimal

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• Balance between efficiency and reliability is important

• Few countries have minimum efficiency standards

Reliability

• This is often a feature of IPP contracts

• Superior O&M is a key to reliability

• Operator training is very important, but raw material in most countries is highly capable, withtraining

3. To what extent do environmental and economic performance requirements dictate thetechnology used and the cost of generation? Please rate them on a scale of 1 (no influence) to 5(critical factor in the decision).

4. Please identify other principal factors influencing choice of coal technology for power generation,and rate them on a scale of 1 (no influence) to 5 (critical factor in the decision)?

Table 1CIAB IPP Survey Responses

Impact of Different Factors on Coal Power Generation Technology Selection1 = Not important 5 = Extremely important

Response No. 1 2 3 4 5 6 7 8 9 10 11 12 14 15 Mean S.D.

Environment 4 4 3 4 2 4 5 3 4 3.5 4 4 5 5 3.9 0.83

Efficiency 4 3 3 4 2 3 4 3 5 4.5 3 5 4 3 3.7 0.9

Reliability 4 4 4 5 5 5 4.5 5 5 5 3 5 4.5 5 4.6 0.6

Maintainability 3 5 4 5 4 5 4 5 4 4 3 4 4 5 4.2 0.68

Technology Cost 5 5 5 4 4 5 5 4 5 5 5 4 3.5 5 4.6 0.55

Technology Maturity 3 4 4 4 5 3 4 4 4 4 4 5 3 5 4 0.65

Technology Risk 3 4 4 5 5 3 3 4 4 4 4 4 5 5 4.1 0.7

Build Time 4.5 4 3 4 3 3 3 3 5 4 3 4 3 3 3.6 0.78

Fuel Flexibility 2.5 4 2 4 2 3 5 3 3 3 3 5 5 2 3.3 1.07

Operational Flexibility 3 3 3 4 2 3 3 3 4 3.5 3 4 3 3 3.2 0.56

Need for Skilled Operators 3 4 1 3 3 4 3 3 3 3.5 3 4 3 5 3.3 0.88

Customer Specifications 4 5 5 4 5 2 3 3 4 4 3 4 3 3 3.7 0.88

Financing Constraints 4.5 5 4 4 3 5 5 4 5 5 4 5 5 5 4.6 0.62

Lender Attitudes 4 4 3 4 4 4 5 4 4 4 4 5 5 3 4.1 0.59

Government Regulation 3.5 4 5 5 4 5 5 4 5 5 4 5 5 1 4.4 1.08

S.D. = Standard Deviation

5. Without revealing confidential information, what is the “ballpark” for the conversionefficiencies your coal-fired power projects in non-OECD countries are achieving - or in the caseof projects planned or under construction, are expected to achieve (indicate whether it is higheror lower heating value). Feel free not to be plant- or country-specific.

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Do you anticipate these efficiencies will change in future projects over the next 5 years? If so,by how much? Is this an important parameter for you?

• Typically 37-38% HHV efficiency today

• Range from 25 to 40% today, 30-47% 5 years from now

• Greater than or equal to 40% HHV

• About 38% HHV for large coal-fired plants, rising only slightly over next few years

• Range 36-38%

• 9000-10000 Btu/kWh heat rate (HHV) (34-38%)

• Around 9500 Btu/kWh heat rate (HHV) today (36%)

• 10000-11000 Btu/kWh heat rate (HHV) today (31-34%) - goal of 9000-9500 Btu/kWh in 5 years(36-38%)

• Anticipate 2-3 percentage points increase in the next 5 years

• Don’t see significant change next 5 years - driven by coal pricing

• Stricter environmental requirements could drive efficiencies higher

• If acceptability of higher efficiency technologies grows, we would be prepared to use them

• Yearly average performance, not just peak performance, is what is important - hence reliabilitycounts as much if not more

• One percentage point on reliability is more important than one percentage point on efficiency

• In a situation where there is competitive pressure on the price of electricity, efficiency will haveto increase

• Supercritical is not sustainable where coal is cheap (e.g. <$20/ton).

6. What would have to happen to help you overcome the barriers and increase power generationefficiency to the 42-45% (lower heating value) range in coal-fired power plants you build? Forinstance, what do you think it would take for you to build a super-critical pulverised coal plantin a non-OECD country? An integrated gasification combined cycle or pressurised fluidised bedcombustion?

What sort of role should government policies and/or international co-operation play inencouraging efficient generation?

• The financial community needs to be convinced of supercritical technology

• Any technology to be selected must be reliable and proven so that non-recourse financing ispossible without significant interest rate penalty. Then it would need to be justified as the lowestcost power by the pro forma.

• EPC contractors would have to be prepared to accept the risk of supercritical - most are not yethappy with that

• Going mildly supercritical (42.5%) is beginning to happen - going to 45% adds too much capitalcost

• Engineering consultants need convincing - European ones are more likely to favour supercriticalthan U.S. ones.

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• Host governments’ and lenders’ attitudes need to be changed

• High efficiency boilers set higher standards for O&M companies - need to develop O&M qualityand risk management

Are there specific measures you would suggest governments might take?

• Government subsidy to overcome environmental problems

• Governments should not intervene unless there is a significant national reason for doing so (e.g.specifying a fuel to achieve balance in fuel mix or use domestic resources)

• Minimum efficiency standards would help, but are not economic

• Large increase in fuel cost or cost of environmental compliance

• Growing concern for climate change will set pressures for higher efficiencies

• Tighter emission limits generally would push towards higher efficiencies

• Key is customer demand (e.g. national minimum efficiency standards as in Germany)

• Greater skill levels in non-OECD countries would help.

7. What is your estimate of the approximate impact of achieving these higher generating efficiencies,on capital cost and on cost per kilowatt-hour of electricity generated (compared to theconventional coal-fired power plant built today)?

Do increased financing costs due to additional risk contribute to your estimated increase? If so,by approximately how much?

• Small, say a few percent on capital cost

• About 15% on capital cost at 45% efficiency

• In the 7-10% range for capital costs, and about 3-5% for cost/kWh

• In the 10-15% range if fuel costs remain constant

• 5-10% on capital cost but narrowing - cost per kWh is close to even

• Financing cost increment is not significant once acceptance for financing is gained.

• EPC costs for pulverised coal are in the range $900-1100, and gasification technologies are in the$1400-1600 range (not including costs due to technology risk, longer construction periods, ordifferences in availability and maintenance costs)

8. In what timeframe do you see new clean coal technologies now being demonstrated becomingtechnologies you would find acceptable for private power projects?

What main factors will be most influential in determining this? How would you judge thesetechnologies in relation to the supercritical pulverised coal plant?

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• PFBC

- In 2000-2002

- already acceptable

- in 2005 and beyond

• IGCC

- Beyond 2010 (strong consensus)

- gas availability is an important negative for IGCC

- could be used in niche circumstances earlier

• No significant efficiency advantage exists for these technologies - supercritical can achieve higherefficiencies today

• Investment cost and performance/reliability are critical for IGCC

• Few demonstration plants are being placed in service

• The lead time for demonstration projects from conception to entering commercial operation is toolong

• Technology owners are not able to predict future maintenance costs accurately

• The technologies are not non-recourse financeable

• The technologies could only be developed and matured in a utility construct and operateenvironment, and utilities are not doing much greenfield building. The IPP environment is notconducive to new technology

• Several more years of operating experience for both IGCC and PFBC will be necessary to raiseinvestor confidence

• More applications are needed to raise confidence

• Manufacturers need to be willing to stand behind their technology’s performance, with >1 yearwarranty, and willingness to put money at risk to cover temporary shortfalls in performance.

9. What is your perception of the competition between coal and natural gas to fuel new powerplants in non-OECD countries?

• Where gas is available at $3/MBtu or less, it will win except where domestic coal is very cheap

• LNG can beat imported coal today

• Gas will be used where pipelines can be built, but LNG is too expensive compared to coal

• Natural gas’s “green” image is a competitive plus

• Competition, already intense, is likely to intensify further with no clear winner in the foreseeablefuture

• Where markets are closed or high fuel import tax exists, domestic coal can beat gas, but nototherwise

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• Anywhere gas is available without differential taxation, it will win

• Quite a few projects began as coal projects, then switched to gas during development

• The rate of new gas discovery has increased rapidly

• Power plants are being used as a foothold in some countries for gas producers to seek anddevelop new fields.

APPENDIX 2

TECHNICAL INFORMATION

2.1 SUPERCRITICAL COMPARED TO SUBCRITICAL COAL GENERATING PLANTS

Plant cycle thermodynamic designs are frequently described as “subcritical”, which is the conventional/mostused design, or “supercritical”. The main difference between these two cycle types relates to the boileroperating pressure. A simplified explanation of these cycles follows:

Subcritical

This design is limited to a maximum practical high pressure steam limit of about 2600 psig (180 bar). Therange of pressures (“main steam”) utilised in power plants extends from very low pressures, e.g. 500psig/35 bar up to this limit. With this cycle, during normal load range operation, the water enters the boilerat relatively cool temperatures (usually 360°F to 450°F/177°C to 230°C) and is heated to form steam; i.e.,going through a phase change. Water entering the boiler is first heated to saturated vapour and then tosuperheated steam. The steam exits the boiler superheated at high temperatures (usually 850°F/455°C to1050°F/565°C, with a current maximum of ~1100°F/595°C).

Supercritical

This design is limited to a minimum practical high pressure steam limit of about 3300 psig (230 bar). Therange of pressures utilised in power plants in operating supercritical units extends from this minimum upto 5000 psig (350 bar). In this cycle, during normal load range operation the “fluid” entering and exittemperatures are similar to the subcritical cycle. In the supercritical boiler the phase change from water tosaturated steam and then to superheated steam does not occur because the operation is above thewater/steam critical point. The critical point is a characteristic of the fluid. Above the critical pressure,“supercritical” fluid states exist, where no difference exists between liquid and saturated vapour. Ifpressure is increased above the critical point, heat addition no longer results in the typical boiling process,rather the fluid is essentially a composite mixture throughout the heating process. It passes through a non-distinct point at which the properties of water change from those of a fluid to those of a gas (steam). Thesupercritical “fluid” entering and leaving the boiler is referred to as “subcooled liquid” and “superheatedvapour”, respectively; not water and steam.

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2.2 SUPERCRITICAL COAL GENERATING PLANT DESIGN FEATURES

When comparing the designs of subcritical, supercritical and ultra-supercritical plants, most of the systemsand equipment, except for the boiler, turbine, and high pressure piping, are the same.

Metallurgy

The practicality and reliability of USC units have been changed by the commercial availability, beginningin the early 1980’s, of new steel alloys which provide higher allowable stresses and longer life at elevatedtemperatures. These new materials provide cost effective solutions to the demanding conditions of theUSC cycle. Recently, new USC plants have gone into operation and have had successful/reliable operation.Research is continuing and the results are promising to increase the current limit on USC plants to 4600psig (316 Bar) and 1140°F (615°C) and beyond in the next five to ten years (3).

High Pressure/Temperature Piping

Main and reheat steam piping ferritic steel (ASTM P91) is currently available and has been proven suitablefor the temperatures and pressures required by the projects listed above. Ongoing development, includingcurrent in plant testing of new tungsten-alloyed 9-12% Chrome steels should shortly raise the practicallimits on the cycle main steam pressure to 5040 psig (350 Bar) and 1115°F (600°C) (5).

Boiler

Use of P91 and the tungsten-alloy materials for boiler superheater and reheater convection surfaces andheaders also provide significant improvement in allowable pressures and temperatures compared to thepreviously available materials for boilers. These new ferritic materials also provide better corrosionresistance and allow more rapid unit start-up rates.

Austenitic steel tubing has been used in the past and will be used on future high pressure and temperaturecycles despite having higher thermal expansion rates and lower thermal conductivity. The high allowablestress and corrosion resistance provided by these materials offset the disadvantages for certain boilersurfaces.

Another improvement is the use of inclined water wall tubes instead of vertical wall tubes. Inclined waterwall tubes provide better heat transfer characteristics and more uniform wall water temperatures.

Turbine

The critical components relative to higher temperatures are usually the high pressure and intermediatepressure turbine rotor materials. Research and development through the initiatives of the American andJapanese utilities, EPRI and EPDC, as well as through the European Power Plant manufacturers within theframework of Cost 501 programs, has resulted in important progress in the development of improvedmaterials for these components (6).

Water Chemistry (7)

The root cause of tube failure is deposition of corrosion products. These corrosion products flow from thefeedwater heaters and systems in units that operate with deoxygenated all-volatile (AVT) cycle chemistry.

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The solution to the problems is to combine a 100% condensate polishing plant with oxygenated treatment(OT) as the cycle chemistry. This changes the form of the oxide which forms on the feedwater surfacesfrom magnetite (with AVT) to ferric oxide hydrate (with OT). The latter has a much lower solubility infeedwater, hence the amount transported to the boiler is much reduced as are the waterwall deposits. Useof OT has eliminated these problems, made the units more reliable and easier to operate, and has saved theutilities many millions of dollars. In the USA alone, over 60 supercritical units have been converted to OTsince 1991.

APPENDIX 3

POWER PLANT EFFICIENCY DEFINITIONS

Throughout the paper, power plant generating efficiencies are defined in terms of lower heating value, orLHV (also known sometimes as net calorific value, or NCV). Higher heating value (HHV) or gross calorificvalue (GCV) of a fuel is the total amount of energy contained in the fuel. The LHV is defined as the HHVminus the latent heat of evaporation of the water contained in the products of combustion, and is a moreaccurate assessment of the “useful” energy of the fuel. An HHV:LHV ratio for coal might be about 1.04,though it will vary depending on the coal composition and heat content.

When generating efficiency is quoted based on LHV, it is defined as the calorific value of the electricityoutput divided by the LHV of the fuel input. Consequently, LHV generating efficiency is higher than HHVgenerating efficiency. For example, a coal-fired power plant with an LHV efficiency of 40% has an HHVefficiency of 38.5%.

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regional trends in energy-efficient coal-fired, power generation

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