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Greenhouse Abatement Options in theStationary Energy Supply Sector

Background Paper

For Discussion by the Annex I Expert Group on the UNFCCC

15-16 September 99

Gene McGlynnEnvironment Directorate

OECD

This paper provides background to a roundtable discussion at the Annex 1 Experts Group Meeting on 16September 1999. Comments on an earlier draft were gratefully received from Evelyne Bertel, Jean Cinq-Mars, Jan Corfee-Morlot, Carlos Ocaña, Jonathan Pershing, and Midori Tani. All errors or omissions arethe sole responsibility of the author. Further comments or questions can be sent to:

Gene [email protected]: +33 1 4524 1686

fax: +33 1 4524 7876


Table of Contents

Participant’s Guide: ................................................................................................. 1

1. Scope and context ................................................................................................. 41.1 Scope of this paper................................................................................................................................................ 41.2 Background and context........................................................................................................................................ 5

2. Past Trends............................................................................................................ 72.1 Changes in Energy Supply.................................................................................................................................... 82.2 Key trends and issues............................................................................................................................................ 9

2.2.1 Institutional.................................................................................................................................................... 92.2.2 Technical ..................................................................................................................................................... 10

3. Abatement measures .......................................................................................... 113.1 Zero-Emission Fuels ........................................................................................................................................... 14

3.1.1 Promoting Renewables ................................................................................................................................ 143.1.2 Promoting Nuclear....................................................................................................................................... 17

3.2 Lower Emission Fuels......................................................................................................................................... 193.2.1 Switching from coal and oil to natural gas .................................................................................................. 19

3.3 Efficiency of energy transformation and distribution ......................................................................................... 223.3.1 Increased use of cogeneration/CHP............................................................................................................. 223.3.2 Improving combustion efficiency in power plants ...................................................................................... 233.3.3 Reducing transmission and distribution losses ............................................................................................ 24

3.4 Some lessons from experience ............................................................................................................................ 263.4.1 Issues Related to Specific Approaches ........................................................................................................ 263.4.2 General Issues.............................................................................................................................................. 27

References................................................................................................................ 29

Annex - Questions on Individual Measures ......................................................... 31



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Participant’s Guide:Roundtable on Greenhouse Abatement Measures in the

Stationary Energy Supply Sector

This paper provides background for a roundtable discussion at the meeting of the Annex 1 Experts Group,15-16 September 1999. The roundtable is intended to examine issues in the development andimplementation of good practice national measures that reduce the greenhouse intensity of stationaryenergy supply through:

• greater penetration of renewables;• greater use of nuclear;• switching from coal and oil to natural gas;• greater use of cogeneration/CHP;• increased combustion efficiency in power generation; and,• reducing transmission and distribution losses.

An agenda of presentations of individual measures by national delegates is below. These presentationsmay raise questions specific to consideration of certain technological approaches, such as those included inthe relevant sections of this paper and summarised in Table A. However, delegates are also asked toconsider and discuss the following questions relating to more strategic assessment of options in this sector:

What are the key social, technical and economic factors driving strategy choice in the stationaryenergy supply sector?

What are the key criteria used to assess potential policy measures? Are these linked to broaderstrategies (e.g. preference for market-based approaches, enhancing competitiveness)?

How far can countries rely on energy market reform to deliver key aspects of energy supplyabatement? How can and has market reform been adapted to address climate change concerns?

Is there a role for international co-operation to contribute to better implementation of energysupply abatement measures?

These questions concern the analysis used to decide on specific abatement measures, given nationalsources of emissions and the range of potential approaches to mitigate these. This strategic policy choiceis central to an effective and efficient response to greenhouse gas emissions.



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Table A - Considerations in assessing technical options for emissions abatement in energy supplyApproach Technical emissions

abatement potential (Kyototimeframe/long term)

Rationale stated for governmentinvolvement (other than greenhousesavings)

Abatement cost (i.e. costs relative toBAU technology)

Other (non-cost)considerations

All Energy SupplyMeasures

Limited by rate of newconstruction, cost of retiringexisting plant/ 100%

See below Varies – see below Preference for demand sideabatement?

Renewables Limited by cost/ Unlimited ifstorage is addressed

Other environmental benefits

Energy diversity

Industry and technologydevelopment/exports

Past support for competing technologies

Cost-effective in niche applications.High cost in many mainstreamapplications, but costs falling. Somecommunity willingness to pay extrafor renewable energy

Some localised environmentalconcerns

Nuclear Zero in many countries, Limiteddue to approval & constructiontimes/ Potentially all electricitygeneration if concernsaddressed


Energy security

Depends on discount rates and fossilfuel costs; but generally high risingwith market liberalisation

Concerns over potentialaccidents, nuclear wastedisposal and weaponsproliferation.

Fuel switching tonatural gas

Limited by turnover rates andinability to convert manyexisting plants/ Very large,limited only by fuelaccessibility

Enhanced competition in energy markets

Other environmental benefits whensubstituting for coal

Energy diversity

Generally low for electricitygeneration, especially for new plantand in competitive markets

Infrastructure availability.

Cogeneration Perhaps a doubling of currentrates/Limited to 30-40%(?) ofelectricity generation

Enhanced competition in energy markets

Information failure in markets


Local industrial/residential development

Low where application is appropriate Limit on suitable sites

Enhancedcombustionefficiency

Significant in new plant butlimited in existing plant/Large

Enhanced competition in electricity markets Gradual improvements very cost-effective; rapid change can be costly

Changes to fuel may swampchanges available through thisapproach

Reducedtransmission anddistribution losses

Limited/Limited unlesscolocation of load andgeneration is much greater

Enhanced competition in electricity markets Small changes cost-effective. Co-location depends on transmissionpricing signals.

Few perceived ancillarybenefits of this approach tomake beyond no regrets actionsattractive



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Roundtable Agenda and ContributionsTopic Speaker

9:30 Meeting Kyoto Targets/Greenhouse reduction optionsand the Stationary Energy Supply Sector (backgroundpresentations)

Lee Schipper/Fritjof Unander/Gene McGlynnOECD Secretariat

10:00 Promoting Renewable Energy: Experience with theNFFO

Richard Kettle[title]ENT DirectorateDepartment of Trade and Industry1 Victoria StreetLondon SW1H 0ETUNITED KINGDOMPhone: +44 171 215 2648Fax: +44 171EMail: [email protected]

10:20 Nuclear Energy Policy in Japan Midori TaniDirector, Global Environment Affairs OfficeMinistry of International Trade & Industry1-3-1 KasumigasekiChiyoda-kuTokyo 100-8901JAPANPhone: +81 3 35 01 78 30Fax: +81 3 35 01 76 97Email: [email protected]

10:40 Break for coffee/tea11:00 Mitigation effects of the domestic implementation of the

EU Directive on electric marketsEmilio MinghettiTechnical Support UnitMinistry of IndustryGeneral Directorate for Energy and Mineral ResourcesDGERM, MICAVia Molise 2I-00100 RomaITALYPhone: +39(06)4705.2525Fax: +39(06)4705.2847/2269Email: [email protected]

11:20 Effects of energy market reform on greenhouse emissionsin the United States

Tracy TerryEconomistDepartment of EnergyOffice of Policy1000 Independence Ave SW PO-21Washington DC 20585UNITED STATES OF AMERICAPhone: +1 202 586 3383Fax: +1 202 586 5391

Email: [email protected]:40 The role of CHP in abating greenhouse gases in Denmark Ture Hammer

Danish Energy Agency44 Amaliegade1256 Copenhagen KDENMARKPhone: +45 33 92Fax: +45 33 11E-mail: [email protected]

12:00 Efficiency Standards for Power Generation in Australia Gwen AndrewsChief Executive OfficerAustralian Greenhouse OfficeGPO Box 621Canberra ACT 2601AUSTRALIAPhone: +61 2 6274Fax: +61 2Email: [email protected]

12:20-1:00 General discussion



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1. Scope and context

1.1 Scope of this paper

Stationary energy use accounted for 64% of total Annex I greenhouse gas emissions in 1990 and around60% in 19961. About 98% of the emissions from this sector are CO2.

The IEA World Energy Outlook projects that, without further policies, CO2 emissions from stationaryenergy use will increase by 27% from 1990 to 2010 in OECD countries, and decline by 12% in transitioneconomies, for a total increase of 14% in Annex I countries (IEA 1998)2. If these projections wererealised, reductions of around 40% would be needed in other sectors - energy and non-energy - to achievethe Kyoto Protocol targets. However emissions in the transport sector are also expected to grow rapidly.Even when considering mitigation options for non-energy emission sources, or alternatively from outsideAnnex 1 through the CDM, achieving Kyoto targets will require abating emissions in the stationary energysector.

While measures to increase energy efficiency from the demand-side will be important to this effort, thefocus of this paper is on measures taken to reduce greenhouse emissions from the supply side. Increasedend use efficiency has played a significant role in restricting greenhouse emissions growth in the past, andthere is considerable potential for further cost-effective action. However, attention to supply sideemissions will also be required. This paper considers the range of approaches to addressing emissionsfrom the supply side, while recognising that this is just one aspect of a comprehensive greenhouse responsestrategy.

The “stationary energy supply sector” (SESS) refers to the transformation and provision of non-transportenergy to end-users. It includes electricity production, oil refining and other energy transformation, as wellas the supply of electricity, natural gas, coal and oil products to end users, whether industrial, commercialor residential. For the purposes of this paper, abatement options aimed directly at upstream energyproduction (oil and gas production, coal mining, etc) are not considered. However, actions addressingenergy transformation and fuel choices will have upstream impacts that can be significant.

In some respects the distinction between the energy supply sector and demand-side measures is artificial.Whenever energy is supplied, there must also be a demand. So measures that affect demand will alsoimpact on supply. However, this paper focuses on the ways that energy is produced and delivered for finalconsumption, rather than on the amount which is used. The paper sets out context on the importance of theSESS to overall greenhouse response, the main strategies taken to address emissions from this sector, andsome lessons from experience to date.

This paper considers sector specific measures only. While there are many potential advantages ofcomprehensive approaches such as carbon taxes and domestic tradable emissions permits, countriescontinue to rely heavily on sector specific approaches, and this paper is intended to support betterdevelopment and implementation of such approaches.

1 From UNFCCC “official” national statistics, excluding LUCF. Based on available data. A number of countries,including some large emitters, have not yet reported data for 1996.2 IEA 1998. Note that in this publication, OECD and transition economies are slightly broader than Annex 1membership. However, the emissions from non-Annex 1 countries within these categories are small and would notsignificantly affect these figures.



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1.2 Background and context

Table 1 shows the breakdown of emission sources from Annex 1 countries in 1996. Stationary energy useaccounts for around 60% of total emissions.3 The largest sub-sector is “energy industries” which includeselectricity generation as well as refining. Electricity production accounts for the largest and growingproportion of these emissions. From 1971 to 1995, Annex II CO2 emissions from electricity as apercentage of total energy CO2 emissions grew from 26% to 35%, despite improvements in the averageemissions intensity of electricity production. (Ellis and Treanton 1997). This is due to the steadilyincreasing share of electricity consumption in total final consumption (see Table 2), and the relatively highemissions per unit of delivered energy from electricity. Table 2 also shows the different patterns of energyuse among different sectors, significant declines in direct combustion of coal and oil, and the growth indirect combustion of natural gas.4

Table 1 - Sources of Emissions in Annex 1, 1996Fuel Combustion 82% Energy Industries 29% Industry/Construction 17% Transport 22% Residential/Commercial/Agriculture 13% Other 1%Fugitive Emissions from Fuels 3%Industrial Processes 3%Agriculture 8%Waste 4%

Total 100% Source: UNFCCC “official” national data. Not all countries have reported data for 1996

There is no direct match between the SESS as defined in this paper and UNFCCC inventory categories.However, “Energy Industries” would be the focus of many abatement measures in the SESS, and accountfor a large percentage of emissions in most Annex 1 countries (see Table 3). Those countries where this isnot the case are those which rely heavily on renewables or nuclear power for their electricity needs. Eventhese countries need to pay careful attention to the energy supply sector in the future if energy demandgrows and the potential for further major hydro or nuclear power is limited. For example, while energyindustries accounted for only 20% of national emissions in Sweden in 1996, growth in this sectoraccounted for 73% of total emission growth. On average, “energy industries” accounted for 46% of thetotal change in national emissions from 1990 to 1996.5

3 That is, the 82% from energy combustion less the 22% from transport. This figure is not exact since some fugitiveemissions are from leakage in gas supplies and so rightly belong with energy supply. Also, the energy used to refinetransport fuels could be allocated to transport but this is not done here.4 Shares of fuels in electricity production are discussed more fully in Section 3.2.1 and summarised there in Table 7.5 Does not include countries where energy industries moved in the opposite direction to total emissions.



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Table 2 - Shares of Fuels in Final Consumption, OECD1971 1980 1990 1996

IndustrialCoal 18% 15% 16% 11%Oil 39% 37% 31% 32%Gas 23% 25% 26% 28%Electricity 14% 17% 22% 24%Renewables 4% 5% 3% 4%Heat 1% 2% 1% 1%CommercialCoal 8% 6% 4% 1%Oil 51% 43% 34% 33%Gas 23% 23% 24% 26%Electricity 18% 26% 36% 38%Renewables 0% 0% 0% 1%Heat 0% 1% 1% 1%ResidentialCoal 15% 11% 8% 3%Oil 35% 27% 20% 19%Gas 28% 33% 35% 38%Electricity 15% 22% 29% 29%Renewables 5% 5% 6% 7%Heat 1% 2% 3% 3%TotalCoal 15% 12% 11% 6%Oil 43% 38% 32% 32%Gas 23% 26% 27% 29%Electricity 14% 19% 25% 27%Renewables 4% 5% 4% 4%Heat 1% 2% 2% 2%

Source: IEA Energy Statistics

Growth in emissions from energy industries was strong in most countries other than EITs. Growth in thissector occurred even in some EIT countries where overall emissions declined. For Annex 1 as a whole,however, emissions from this source grew by only 1% from 1990-96, compared with an increase in overallemissions of 2%6. This is due to the decline in EIT emissions from this sector and to a large fall inGermany and the UK for reasons of economic and sector policy changes. In the case of the UK, subsidyreform resulted in significant reductions in emissions.

6 Source: UNFCCC “official” national data. Data for Liechtenstein, Lithuania, Russian Federation, Slovakia, Slovenia, Ukrainewere unavailable. 1995 data used for Iceland, Italy, Luxembourg, Japan, and Spain. 1994 data used for Portugal. Excludes LUCFsector. If data for missing EITs for whom data is lacking were included, both energy industry and overall emissionswould likely decline. It should also be noted that increases in some countries and declines in others nearly canceleach other out. As a result, the overall change in Annex 1 emissions is very small, so small changes would lead tolarge changes in percentage outcomes. Therefore, aggregate figures should be treated with caution.



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Table 3 - Importance of Energy Industries to Annex 1 EmissionsEnergy industriesemissions aspercent of totalnationalemissions, 1996

Percentagegrowth in energyindustriesemissions, 1990-96

Energy industriesemissions growthas a percentage oftotal nationalemissions growth,1990-96 a

Estonia 81% -35% 56%Romania 69% 23% -21%Denmark 48% 70% 87%Bulgaria 46% 13% -9%Poland 45% -25% 51%Greece 42% 4% 29%Czech Republic 38% -41% 103%Finland 37% 53% 188%Australia 37% 15% 64%Monaco 35% 38% 43%Germany 34% -13% 46%Hungary 34% -28% 46%United States 30% 8% 29%Japan 29% 6% 34%United Kingdom 29% -13% 72%Spain 27% 12% 40%Italy 27% -6% -110%Latvia 25% -53% 29%Ireland 25% 30% 117%Netherlands 24% 10% 23%Portugal 24% 1% 3%Canada 21% 5% 9%Sweden 20% 61% 73%Belgium 20% 4% 8%Norway 17% 32% 36%Austria 16% 4% 18%France 11% -9% -99%New Zealand 8% 4% 11%Luxembourg 8% -56% 33%Switzerland 2% -2% 5%Iceland 0.1% -15% 0%Source: UNFCCC “official” national data. Data for Liechtenstein, Lithuania, Russian Federation, Slovakia, Slovenia, Ukrainewere unavailable. 1995 data used for Iceland, Italy, Luxembourg, Japan, and Spain. 1994 data used for Portugal. Excludes LUCFsector.a - A negative number in this column indicates that energy industries emissions moved in the opposite direction to total emissions.For Romania and Bulgaria, this means that energy industry emissions increased while total emissions declined. For Italy andFrance, energy industry emissions fell while total emissions increased.c - Russian data are available for total emissions but not for energy industries. Thus, they are excluded from this analysis.However, with Russian total data included, total emissions decline for Annex 1 countries. It is likely that energy industries’emissions also decline .

2. Past Trends



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2.1 Changes in Energy Supply

Growth in emissions from stationary energy use has been relatively subdued over most of the last 25 years,with CO2 emissions only 12% higher in 1995 and 16% higher in 1996 than in 1971 (see Figure 1). This isthe result of conflicting drivers of emissions in this sector. Both GDP per capita and population have risen,leading to greater levels of output and energy use. However, the energy intensity of production (i.e. thefinal energy consumed per unit of production) has fallen by almost 40% from 1971 to 1996. Combinedwith a small fall in emissions intensity (i.e. tonnes of CO2 per unit of final energy consumed) largely dueto an increase in nuclear and some shifts to natural gas, this has not quite offset the increases in output,leading to a small increase over time in emissions (see Figure 2). This suggests that, to achieve thereductions in the energy sector required to meet Kyoto targets, even with continuing energy efficiencyimprovements, will require attention to the supply side of the equation, which is the focus of this paper.

Outside OECD, Annex 1 emissions are dominated by transition economies of eastern Europe and theFormer Soviet Union, where massive falls in GDP following economic and political restructuring around1990 have led to significant falls in energy-related emissions in most of these countries.

Figure 1 - Growth in Emissions in OECD countries

Source: IEA Energy Statistics

OECD Energy CO2 emissions 1971-1996

0

50

100

150

200

1971

1974

1977

1980

1983

1986

1989

1992

1995

Transport

Stationary



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Figure 2 - Contributors to CO2 Emissions Growth from Stationary EnergyOECD 1971-96

Source: IEA Energy and CO2 statistics

2.2 Key trends and issues

While a wide range of factors influence emissions from the energy supply sector, a few key influences willbe important in setting the context for greenhouse abatement in this sector in future:

2.2.1 Institutional

Importance of other policy concerns - Until recently, greenhouse has been a marginal consideration, if any,in national energy policies. Following the oil shocks of the 1970s, energy (especially oil) security was amajor policy driver responsible for many developments on both the supply and demand side. Whileconcern with energy security has lessened in the 1990s, it remains a policy concern, and an important onefor many countries. Other environmental concerns have also been important to energy policy since the1970s, especially air quality and sulphur issues. In recent years, ensuring competitive and reasonablypriced energy supply has been a major energy policy driver, leading to substantial market reform. This isdriven in large part by concerns to ensure the international competitiveness of national economies. It isonly very recently, and more so since Kyoto, that climate change has become a central concern in energypolicy in most countries. Therefore, many “greenhouse” policies in the energy sector are actually policiesimplemented for other reasons. While some non-greenhouse energy policies are compatible with orindirectly linked to abatement, others are neutral or lead to increased emissions. The challenge of meetingKyoto targets means countries may need to design energy policy solutions which meet different policyobjectives simultaneously.

Energy market reforms - Governments have traditionally played a major role in the provision of energy.Electricity generation and distribution assets are often government owned, and many aspects of energysupply are tightly regulated. A number of governments are engaged in reform programmes to open theenergy supply sector to greater competition. This has a number of effects, with differing impacts ongreenhouse emissions. A key objective of reform is to lower energy prices, so it seems likely that overall

-

50

100

150

200

1971

1975

1979

1983

1987

1991

1995

Ind

ex (

1971

= 1

00)

GDP percapita

Population

CO2

EmissionsIntensity

EnergyIntensity



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consumption will increase, especially as reform can lead to the reductions in demand managementprogrammes. However, there will also be many effects on the supply side. For example, in electricitygeneration, greater competition could favour investment in combined cycle gas rather than more capital-intensive coal (or nuclear) power stations. Competition may also enhance pressures to increase theefficiency of existing generating plant and transmission/distribution systems, provide signals for load andgeneration to locate close to each other so as to reduce transmission losses, or improve peak loadmanagement. Central to the effect of market reform on greenhouse will be the incentives it provides forfuel switching. Here the picture is mixed, with the UK experiencing a “dash for gas” while Nordiccountries appear set to shift to a higher carbon fuel mix (moving away from hydro and nuclear towardsnatural gas). Some countries have introduced environmental regulations with energy market reforms tobetter ensure simultaneous achievement of economic and environmental objectives. Countries need todesign abatement measures that recognise the energy market context, which is increasingly competitiveand dynamic.

2.2.2 Technical

Long planning horizons - Most energy infrastructure is long-lived. This means that change is difficultexcept over long time periods. For example, projections by the US EIA show that by 2000, 80% ofelectricity supply in 2010 and two-thirds of supply in 2020 will already have been built7. As it is difficultand expensive to substantially change the operating characteristics of existing plant, this means thatinvestors in energy supply must be considering greenhouse outcomes today to make substantial reductionsin the Kyoto timeframe, especially as energy supply options can take 2-5 years to plan and construct beforethey are operational. Effective control of energy demand will further limit the ability to make majorchanges on the supply side since there will be less turnover of plant. So, interactions between supply anddemand abatement strategies can be important.

Increasing electrification - the share of electricity as a source of energy CO2 emissions has risen steadilyfor Annex II countries, from 26% in 1971 to 35% in 1995. This increase occurred despite a steady declinein CO2 emissions per kWh, due to increased use of nuclear power and renewables, switching from coal togas, and increased production efficiencies. The latter has occurred through technologies such as combinedcycle gas turbines (Ellis and Treanton 1998). The share of electricity in final energy consumption isincreasing for two major reasons. First, there has been more relative growth in the commercial andresidential sectors than in the industrial sectors. These sectors have a relatively higher reliance onelectricity as an energy source and there is an increasing range of electrical applications (electronicconsumer goods, computers and related communications equipment, etc) for which there are noalternatives. Secondly, in all sectors, the share of energy from electricity has grown substantially (seeTable 1). This increase comes mostly at the expense of direct combustion of oil products, and reflectsgovernment efforts to reduce reliance on oil, as well as natural advantages of electricity as an energysource. Increasing electrification slows any improvements in emissions intensity of energy supply, as itcan require up to 3 units of energy for every unit available for final consumption8. The ratio of TPES/TFCin OECD countries has risen directly in line with the increasing role of electricity in energy supply. If therate of electrification continues, it will provide an extra challenge to keeping emissions under control, aswell as emphasise the requirement for low or no-emissions electricity production.

7 Figures for the US only. From EIA 1999, Baseline Scenario.8 This does not mean that electrification necessarily increases overall emissions however. If an electric application isfar more energy efficient for the user, it can lead to a reduction in overall energy demand which can offset theincreased emission intensity.



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Nuclear - between 1973 and 1996, nuclear rose from only 1% of total energy supply to 11%, althoughmost of this growth occurred from plant orders placed before 1980. Nuclear accounted for almost 40% ofthe total growth in primary energy consumption over this period. However, recent experience suggests thatnuclear may play a limited future role in all but a few OECD countries. This means that the successes inreducing emissions intensity of energy supply achieved through nuclear will need to come from othersources. Through the 1980s and early 1990s, switching from coal to gas and increases in the efficiency ofgeneration have allowed this. However, such changes will need to continue, or other zero-emissionsources will need to grow rapidly, to continue this rate of decline in emissions intensity. Some countriesare already discussing early phaseout of their nuclear capacity, and much existing nuclear capacity willstart reaching the end of its life in the first quarter of the next century, further emphasising the importanceof addressing the role of nuclear.

3. Abatement measures

In developing approaches to greenhouse response, governments will address the key sectors causingemissions, of which the energy supply sector will be key. Countries have a range of approaches availableto abate greenhouse emissions from the energy supply sector. In broad terms, these include:

− Switching to zero-emission fuels:− Increased use of renewables− Increased use of nuclear

− Switching to lower-emission fuels− Switching from coal or oil to natural gas

− Improving the efficiency with which energy is transformed and distributed− Increased use of cogeneration/CHP− Improving the efficiency of combustion in “standard” fossil fuel power plants− Reducing transmission and distribution losses

There are then a host of potential measures to achieve one or more of these outcomes. Strategicconsideration of which approaches offer the most potential and which types of measures are favouredresult in selection of a specific set of measures. These choices could include elements of all the aboveapproaches. Factors that could affect strategic assessment of measures could include cost-effectiveness,equity impacts, ancillary costs and benefits (i.e. impacts on other policy goals such as environmentalimpacts, energy security or innovation), or perceptions of risk and technological potential.

Figure 3 illustrates the role of strategy in moving from technical options to specific measures. The split ofsectoral emissions determines the total abatement potential from various sectors and sub-sectors.Consideration of technical options indicates the technical potential of different approaches, and their costsand other impacts. Strategic choices are then made on the range and types of measures undertaken, basedon explicit and implicit criteria. Some measures will support a range of technical approaches, while otherswill be designed to achieve more specific outcomes. Those measures chosen for implementation shouldaddress the assessment criteria as well as the technical potential of different approaches.

Some measures address all approaches by providing comprehensive signals to abate emissions throughoutthe economy. For example, carbon taxes or domestic tradable emissions permits would allow companiesand individuals to choose cost-effective abatement methods across the range of technical approaches. Fortechnical and other reasons, most countries have chosen not to implement such comprehensive measures.



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Even those countries that have introduced carbon taxes have also adopted a range of sector-specificinitiatives to address emissions. Therefore, it is important that such measures be implemented in aneffective and efficient manner. In considering such measures, a good starting point is to consider what, ifany, specific benefits are provided by sectoral measures. If these sectoral measures are implementedbecause of shortcomings in more comprehensive market measures, it will be important that they aredesigned and implemented so as to effectively address such shortcomings.

Figure 3 - Relationship of sectors, technical approaches and measures

In considering options to reduce emissions from energy supply, it is important to consider the range oftechnologies available to meet energy needs. Some energy applications have limited options fortechnological choice. For example, many household and commercial appliances, and some industrialapplications are only available for use with electricity. Others, such as space and water heating, have arange of potential fuel and technology choices.

Within electricity generation, the operating characteristics of nuclear and coal-fired power make them verysuitable for base load but not peaking capacity. Oil, gas, and hydro, on the other hand, have moreflexibility for matching load, while also being useful for baseload when the economics stack up. In somecases, generation is available primarily for standby or emergency purposes, and it is difficult toeconomically justify advanced technologies in these situations. While cogeneration can be highly efficient,it requires a matching of electricity and heating needs which is not always present.

Availability of resources also has strong influences on fuel and technology choice. This is most obviousfor renewable sources such as wind, solar and hydro where resource quality and availability is verylocation-specific. However, access to gas pipelines, transmission grids, coal mines, etc can influence theeconomics of choices such as fuel, whether to use cogeneration or not, etc.

Transport Stationary Energy Other

NuclearRenew. FF switching

Gen/TranEffic

Carbon taxes

Energy Market Reform

Non-fossil support

Ren subsidies

Sectors

Measures

etc.

Demand sideTechnicalApproaches

Supply Side

Social Factors Preferred Strategic Approaches

Economic Factors Assessment Criteria

Technical Factors Domestic/International Action

Strategy



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Within electricity generation, there is a wide range of technologies available, all with different costs andemissions profiles. Table 4 broadly indicates the range of choices. This shows that both costs andemission vary widely within fuel and technology choices. Even the same technology in different locationscan vary considerably due to differences in fuel costs, labour costs, load factors, etc. This table alsoindicates the difficulties in calculating the emissions abatement costs of different approaches, since there iswide variation in both the BAU technology and the alternative. In principle, the cost-effectiveness ofoptions affecting technology in fuel choice in electricity generation is a function of the reduction inemissions relative to BAU divided by the difference in levelised cost. However, in practice, it is difficultto make such generic cost comparisons for a number of reasons, beyond the spread of potential costs andemissions.

• Table 3 only includes generation costs. In some cases, technologies such as local renewableapplications or cogeneration can reduce transmission and distribution costs, which can account forup to half of the cost of delivered electricity. It is this delivered cost on which cost comparisonsshould theoretically be made, although it can be difficult in practice to allocate fixed and marginalcosts of transmission and distribution.

• A proper analysis of relative costs and emissions should be based on full life-cycle emissions.While emissions from actual combustion of energy are relatively easy to calculate and compare, itis harder to correctly allocate the upstream emissions. Venting and flaring from natural gasproduction, methane emissions from coal mining, processing of nuclear fuel, emissions fromcement production in large hydro dams, growing and collecting biomass fuels, and construction ofsolar panels can all lead to significant emissions. Measuring and tracking these changes throughthe energy supply chain is difficult, and while the figures in Table 4 reflect an attempt to completea life-cycle analysis, caution should be used in interpreting these figures. While this paper doesnot deal directly with measures to reduce upstream emissions, changes to fuel demand will alsohave upstream impacts. Similarly, upstream measures will affect the effectiveness of measures inthe energy supply sector.

• Table 3 does not include other ancillary impacts of different forms of electricity production. Forexample, there are many non-greenhouse environmental concerns associated with use of nuclearand large hydro generation. Coal-based electricity is a major source of sulphur as well asgreenhouse emissions, and cogeneration can lead to increased levels of NOX emissions in denselysettled areas. Renewable sources such as wind and wave technology have environmental concernsattached to them, although these tend to be far more localised. All of these effects have values thatshould be accounted for in assessing cost-effectiveness.

• Due to different ownership structures for different technologies, there may be different sharing ofrisks amongst different technologies. For example, risks of outages or accidents from small scalerenewables and cogeneration will generally be borne by the user/operator while those for largescale plant will generally split risks be borne by the operators and charged to users. In some cases,such as nuclear, there may be implicit or explicit sharing of risks with governments. Thesedifferent approaches have implications for the relative valuation of different technologies.



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Table 4Comparison of costs and emissions from different fuel sources and technologies

Energy Source Emissions(g CO2/kWh)

LevelisedGenerationCost(cents/kWh)

Coal 650-1300 3.5-7.6

Gas 400-1000 2.4-8.4

Nuclear 25 3.9-8.0

Renewables Biomass 15-27 2.6-7.8a

Hydro 3.6-11.6 3.5-6.9 Solar PV 98-167 19.6-138 Wind 7-9 4.2-45.7 Geothermal 79 3.6-17 MSW or industrial waste 5.9-10.6

CHP Gas 120- Coal 430

Sources: IEA/NEA 1998 (based on generic assumptions at 10% discount rate), IEA 1998b, IEA 1998c,Echavarri, 1998, EC 1995 McDonald et al 1996, IEA GHG R&D. As there are many differences inmethodologies and assumptions between these sources, these comparisons should be seen as broadlyindicative only.a - low end of costs based on CHP co-firing

3.1 Zero-Emission Fuels9

3.1.1 Promoting Renewables10

Annex 1 countries have implemented a large number of programmes to increase the share of renewableenergy sources in energy supply. These include:− Economic and fiscal incentives− Green pricing− Guaranteed markets and/or favourable prices− Government-supported R&D− Regulations and standards

9 As table 3 shows, no fuels are really zero-emission fuels on a full life-cycle basis. However, with the possibleexception of Solar PV and Geothermal, renewable and nuclear emit far less than 10% of even low emission fossil fuelgeneration per kWh.10 This section draws heavily on IEA 1998b for background, which also provides a detailed summary of renewableenergy policies in place in IEA countries as of early 1998.



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− National targets− Voluntary actions− Information and education campaigns

Renewable energy contributed about 9% of total primary energy supply in the OECD in 1996, although thecontribution varies considerably between countries. This is a marginal increase since 1990. When hydrois excluded, the contribution is about 7%, again up marginally since 1990. Biomass accounts for morethan 80% of non-hydro renewables. While renewables have only marginally increased their share, theyhave experienced very rapid growth relative to overall TPES. For example, TPES from wind increased by175% over the period and from solar by 70%, while total TPES increased by only 12%.11 Most OECDcountries’ capacity for new large hydro is limited by access to new sites and environmental considerations.Combined with cost considerations, this has led most energy forecasts to predict a continued limited shareof energy from renewable energy in the Kyoto time frame.

Support for renewable energy development appears to be a widely implemented approach to greenhouseabatement in the SESS. This may be because it is politically popular and is seen to contribute to othergovernment goals such as improved local air quality, energy diversity, promotion of technologicalinnovation, increased exports, employment, support for regional development and decentralisation ofelectricity supply. However, renewable energy in most applications is still more expensive than“traditional” sources, so that these measures generally go beyond “no regrets”.12 In some applications, thisis not the case. For example, in remote areas where transmission or transport of fuels and maintenance areexpensive, renewables can be cost-competitive. And in some cases, lower cost renewable applicationssuch as wind and biomass can compete with traditional sources. However, electricity from renewables willtypically cost at least 1-2 cents per kWh more than traditional sources, and often much more. Anadditional 1 cent per kWh, at average OECD emissions intensities in 1995, translates to a cost of around$60/tonne of carbon saved. Where the cost difference is higher, the carbon abatement cost would also beproportionately larger.

An important question for renewable energy support policies is therefore the extent to which, over the longterm, they lead to renewable energy becoming cost-competitive with traditional energy sources withoutdirect government intervention. This is generally through policies that help to push renewable energy“down the learning curve”, as prices fall quickly with increased rates of consumption. On the other hand,continuing subsidies for renewable energy can be seen as recognition of the environmental benefits ofthese technologies. In essence, this is an alternative to increasing charges on fossil fuels to reflect theirhigher emissions levels.

Green electricity schemes, where consumers voluntarily pay more for renewables-based energy, takeadvantage of consumer preferences for renewable energy and willingness to pay a “renewable premium”.Green pricing schemes differ from other renewables support programmes in that they are “no regrets”measures and do not require government intervention other than to facilitate (or at least allow) theirimplementation. To some degree, such schemes are counter to the polluter pays principle, as it is thoseconsumers causing the least impact who pay most. Externality pricing would address this issue. However,green pricing consumers are also paying for some of the hedonic properties of renewable energy beyondtheir direct use value.

11 Source: IEA energy statistics. Note that statistics on some renewable energy are prone to more error than otherenergy statistics, especially non-combustible sources, and should be interpreted accordingly.12 In the sense that their direct costs could not be justified on pure financial grounds. However, the otherenvironmental and economic benefits of renewable energy development could make them “no regrets” options in abroader context.



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The different forms of government support for renewables operate at different points in the path fromdevelopment to use, and have different target audiences, as shown in Table 5. Therefore, it can be sensibleand common for a range of renewable energy support measures to be implemented simultaneously.However, it is important for effective policy-making to consider how the different support elementsinteract, and especially the timing of effects. For example, it would be premature to promote wide-scalemarket uptake of technologies that still require considerable basic research. Similarly, it would beinefficient to continue to provide basic R&D support to a technology which is well-developed and alreadyin commercial use.

Table 5 - types of support for renewable energyMeasure Point of Operation Target Audience13

R&D support Basic research to earlycommercialisation

Researchers, RE technologysuppliers

Project-based financial support Commercialisation RE generators

Guaranteed markets or buybackrates

Commercialisation Electricity retailers

Green pricing Market creation Electricity retailers andconsumers

Information and educationcampaigns

Market “normalisation” Consumers

Renewable energy support policies also differ in their coverage and definition of renewable energy. Forexample, some specifically support PVs or biomass, while others explicitly avoid picking technologywinners, and look for the most cost-effective use of renewable energy. This raises the question of thescope of “renewable” energy. While there is wide agreement on inclusion of technologies such as wind,PVs, biomass waste, mini-hydro, tidal and wave power, differences arise as to whether large-scale hydro,municipal waste to energy schemes, heat pumps, landfill gas, or even coal-seam methane capture should becounted as renewables. How renewables are defined will affect the costs of and scope for renewableenergy. Some of the categories in question can be some of the more cost-effective options. The level anddistribution of R&D funding for different renewable technologies varies considerably amongst countries,reflecting both different national circumstances and different criteria for choosing renewable energysources to focus on. There are also differences in how support programmes handle supporting technology,such as batteries and fuel cells. These technologies can help to promote renewables by addressing theirintermittent nature, but can also be used with non-renewable energy sources.

In considering measures to promote renewable energy, issues to be considered include:

Should renewable energy support be general or for specific technologies? If specific, what criteriashould be used to choose technologies?

Does the intermittent nature of some renewables put limits on the future role of renewables inpower generation? How should support for linked technologies - for example batteries and fuelcells - be handled?

13 Due to the diversity of programmes in place, the target audience can vary. So, these should be seen as indicativeonly.



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What point(s) of intervention offer the most benefit to long-term uptake of renewable technologies?Should policies target innovation in renewables rather than market creation? How can differentsupport programmes be effectively mixed? Are answers to these questions affected by the planningtime frame used?

How does the willingness of many consumers to pay a premium for renewable energy affectpolicies to support renewables?

3.1.2 Promoting Nuclear

The main mechanisms by which Annex 1 countries promote nuclear energy are:− R&D support− Financial subsidies− Direct investment− Information programmes

OECD countries vary considerably in their reliance on nuclear energy (see Table 6). While France derivesaround 78% of its electricity from nuclear, 13 countries have no nuclear, and a number of these haveindicated they do not see nuclear as a viable option in the future. The United States, France and Japanaccount for more than two-thirds of all nuclear power generation in the OECD. If the electricity generatedfrom nuclear were generated from other fuels14, total OECD emissions would have been about 1.2 billiontonnes of CO2 higher, an increase of about 10%. Sweden and Germany are considering options to phaseout the use of nuclear and an issue they will face is how to replace this electricity output while meetingtheir Kyoto commitments. Other countries could face the same issues over the first decades of the nextcentury as ageing nuclear infrastructure will come due for decommissioning. 19% of current OECDnuclear capacity is due for retirement by 2015 (Vera at al 1998)

The cost of nuclear energy relative to fossil fuels depends on a range of assumptions, especially discountrates, fossil fuel prices, load factors and lifetimes. For example, a study of generation costs in 12 countriesusing nuclear power showed that, at a 5% discount rate, nuclear was cost-competitive with either coal orgas in all 12 countries. However, at a discount rate of 10%, it was competitive in only 4 countries, 2 ofwhich (France and Japan) had very high fossil fuel costs and considerable experience with nuclear. This isbecause of the capital-intensity of nuclear, with 65% of the total levelised cost being capital costs. Franceand Japan were also the only countries where projected nuclear costs were lower than gas. The averagedifference between the cost of nuclear and the cost of coal for all 12 countries was 0.25 cents per kWh.For gas, the average difference was 0.9 cents per kWh. At these price differentials, and at averageemissions intensities, this would indicate a carbon abatement cost of around $10/tonne for switching fromcoal, and $65/tonne for switching from gas. At higher discount rates or lower fossil fuel prices, the costswould be greater. As nuclear may also carry higher perceived risks than other fuels, investors may applyhigher discount rates to these investments than others, making the abatement costs higher.

A challenge for nuclear in the Kyoto context is the time of construction. For nuclear plants completedfrom 1978 to 1997, the average construction time was 6.7 years.15 Given the need for planning andapprovals prior to construction, it would be difficult for new plants to be built before the start of the first

14 At the OECD non-nuclear average emissions intensity in 199515 Source: IAEA 1998. In Japan, which accounted for 15 of the 39 plants completed in the 1990s, the averageconstruction time was around 4 years. So, it may be quicker to build plant in countries with strong reliance onnuclear.



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budget period in 2008-2012. And in the intervening years, the bulk of generation capacity would alreadybe built. So, as a greenhouse abatement policy, the role of new nuclear may be strongly constrained in theKyoto time frame. However, there are opportunities for upgrading of capacity in already existing nuclearplant in a shorter time frame.

Annex 1 countries have provided substantial financial support for nuclear through R&D funding. From1974 to 1997, almost $150 billion was spent on nuclear R&D in OECD countries, with the figure standingat over $4 billion in 1997. More than 75% of the total has come from Japan, the United States andGermany. While the percentage of total government R&D funding devoted to nuclear has been declining,it still accounts for more than 50% of total OECD government energy R&D, far more than any other classof technology (see Figure 4)16.

Figure 4Nuclear’s Share of Reported OECD Government Energy R&D Spending, 1974 to 1997

Source: IEA 1999Notes: Data prior to 1990 do not include Finland or France. Data on Hungary are not included.

Following rapid growth in nuclear in the 1960s and 1970s, concerns about costs, severe accidents,radioactive waste disposal and nuclear weapon proliferation led to a rapid reduction in construction of newplants in most OECD countries. 60% of current OECD nuclear plant capacity was ordered before 1973. Afurther 20% was ordered before 1979. The remaining 20% was ordered after 1979 in France, Japan, andKorea. (IEA1999) However, some OECD countries and a number of EITs plan for nuclear to play asignificant role in future energy supply. Nuclear energy does not generally enjoy strong public support,and public protests have affected construction of nuclear power plants in the past. Combined with thehighly capital-intensive nature of nuclear power stations, and risks associated with costs of nuclear wastedisposal, this can make nuclear options seem unattractive to many investors. Therefore, direct governmentintervention may be required and is often used to support further development of nuclear power. This cantake the form of direct investment, financial support or investor guarantees.

16 Figures for nuclear R&D spending include both fission and fusion technologies.

0 %

1 0 %

2 0 %

3 0 %

4 0 %

5 0 %

6 0 %

7 0 %

8 0 %

1 9 7 4 1 9 7 6 1 9 7 8 1 9 8 0 1 9 8 2 1 9 8 4 1 9 8 6 1 9 8 8 1 9 9 0 1 9 9 2 1 9 9 4 1 9 9 6

n u c le a r p o w e r , fo s s il fu e ls re n e w + c o n s e rv .



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Table 6 - Shares of Nuclear in Electricity Generation% of Electricityfrom nuclear

% of Total Nuclear inOECD

France 78% 19%Belgium 58% 2%Sweden 52% 4%Switzerland 45% 1%Hungary 40% 1%Korea 33% 4%Spain 32% 3%Japan 30% 14%Germany 29% 8%Finland 28% 1%United Kingdom 27% 5%OECD weighted average 24% N/ACzech Republic 20% 1%United States 20% 34%Canada 16% 4%Netherlands 5% 0%Mexico 5% 0%Australia, Austria, Denmark,Greece, Iceland, Ireland, Italy,Luxembourg, New Zealand,Norway, Poland, Portugal, Turkey

0% 0%

In considering measures to promote nuclear energy, issues to be considered include:

Given difficult economics and wide public opposition in many countries to increases in nuclearpower, is nuclear a viable option for significant abatement of greenhouse gases in future?

How should the potential rise in emissions that will generally come from decommissioning ofnuclear plants (and replacement with fossil fuels) be handled?

Is there justification for spending such a large proportion of government energy R&D on nuclear?

3.2 Lower Emission Fuels

3.2.1 Switching from coal and oil to natural gas

Actions taken by Annex 1 countries to promote fossil fuel switching to natural gas include:− Prohibitions on use of some fossil fuels in some applications− Direct investment or subsidisation of gas infrastructure− Energy market reform to promote competition, increase access and reduce prices for natural gas− Reform of subsidies for high greenhouse intensity fuels



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− Subsidies for investment in new gas-fired equipment

Under any realistic projection, fossil fuels will continue to play a major role in energy consumption forsome time into the future. Within the range of fossil fuels, there are substantial differences in greenhouseperformance. Coal-fired stations will typically emit 750-1250 g CO2/kWh, while gas stations could emit430-700 g CO2/kWh. Actual performance will be affected by the characteristics of the fuel used, the typeand age of plant constructed and load factors, among other things.

Table 7 shows that the share of all fossil fuels in electricity production has declined since 1971, whichwould suggest a substantial decline in greenhouse emissions per kWh. However, this is largely due to theincreased share of nuclear. Amongst fossil fuel plants, there has been a large rise in the share of coal-firedpower, a rapid decline in the share of oil and the share of gas has increased a little. Overall, this indicatesthat the emissions intensity of fossil fuel powered plant has risen. Given the already small role of oil-firedgeneration, and the limited greenhouse benefits from switching, the main focus of abatement policy in thisarea would appear to be shifts from coal to gas. Outside the electricity sector, natural gas has increased inmarket share, especially in the residential sector, while coal and oil have lost market share. (Electricity hasseen the biggest increase in share - see Table 2). In this area, switching from oil and electricity use to gasappear to offer the greatest potential.

Table 7 - Fuel Shares in OECD Electricity Production, 1971-96Coal Nat Gas Oil Nuclear Hydro Other

Renewables

Percent of Total Electricity Production1971 40% 13% 22% 3% 23% 0%1980 41% 11% 17% 11% 19% 0%1990 41% 10% 9% 23% 15% 2%1996 39% 12% 7% 24% 15% 2%

Percent of Fossil Fuel Electricity Production1971 53% 18% 29%1980 59% 16% 25%1990 68% 17% 15%1996 66% 21% 13%

In many countries, energy production from natural gas is already expected to increase rapidly. In the USEIA reference case, for example, natural gas consumption in the US in 2020 is nearly 50 percent higherthan the 1997 level. Onshore and offshore production are projected to increase by 57 and 14 percent,respectively, and pipeline capacity to increase by 32 percent over 1997 levels (EIA 1999). Someprojections for the EC show a near doubling of investment in gas pipelines and LNG gasificationfacilities over the same time period (EC 1996). Such rates of growth are possible, but there maybe limits to the increased rate at which gas can be introduced without stretching the technical andeconomic capacities of the industry.

Given the many types of plants, and roles in energy supply, it is difficult to calculate even a rough genericcost of emission abatement through fuel switching beyond business-as-usual. The investment decisionsinvolved are generally long-term and often fundamental to the profitability of the firm(s) involved. So,strong incentives for change are likely to be required in many cases.



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Fuel switching in electricity generation is generally an investment decision. Once a plant is built, it isoften difficult to change the fuel source without substantial changes to the plant. A similar situation arisesin direct combustion, although the capital investment required can be smaller and made more often. Forexample, households that switch from electric or oil space or water heating to gas will often require newheating systems to be installed. For hot water, new investments may be made every 10-15 years,considerably shorter than the average lifetime of a power station. However, households only have thisoption when the distribution infrastructure for natural gas is present. In many areas, especially outsidedense urban areas, this is often lacking and gas is not a viable option. By contrast, almost all householdsand businesses in Annex 1 countries are already connected to the main electricity grid.

There are some opportunities to switch fuels in existing plant through repowering. A US DOE studyexamined potential for repowering coal-fired stations to operate on natural gas in the United States. Thiswould significantly improve emissions performance, but is a major capital investment. Key factors thataffect the costs of such changes are the relative prices of fuel, whether or not excess gas pipeline capacityexists or needs to be built, and whether the costs of non-greenhouse externalities are considered. Thisstudy concluded that at a carbon permit price of $50 per tonne of Carbon, it would be cost effective torepower up to 27 GW of coal-fired power to gas, with an emission savings of 30 MtC. At a price of $100per tonne, up to 147 GW, accounting for 134 MtC could be cost-effectively repowered. These figuresrepresent about 3% and 13%, respectively, of total stationary energy emissions. At the lower carbon price,including an externality cost for SO2 and NOX would substantially increase the level of cost-effective.repowering. (IWG 1998)

An important consideration in the fuel-switching context is existing subsidies to fossil fuel consumption,especially coal. While there have been some reductions in energy subsidies in recent years, they stillremain significant in a number of Annex 1 countries. Subsidisation of fossil fuels overall makes it moredifficult for lower emission fuels to compete. Within the fossil fuel class, subsidies to coal are especiallydamaging from a greenhouse perspective. Case studies in Annex 1 countries show potential for emissionreductions of up to 16% relative to the base case from subsidy reform. (OECD 1998)

This issue also relates to energy market reform, where electricity and gas reform often proceed on differenttracks and in different time frames. As a key aim of both processes is to reduce prices, it is important thatgas reform and electricity reform move together to integrated energy markets to ensure effective incentivesfor appropriate fuel choice.(Allen Consulting Group 1998) Given the ability of investments to lock inemissions for 30 years or more, this is an issue that should be addressed with some urgency.

In considering measures to promote fuel switching to natural gas, issues to be considered include:

How can policy provide incentives for fuel switching without encouraging greater overall use ofenergy?

Are there constraints on global gas supplies which limit the role of fuel switching as a greenhouseresponse option? To what extent is support needed to develop gas production and distributioninfrastructure?



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3.3 Efficiency of energy transformation and distribution

3.3.1 Increased use of cogeneration/CHP

Actions taken by Annex 1 countries to increase the use of cogeneration/CHP include:− Energy market reform to promote greater competition and increase pressure for more efficient

generation− Support for R&D for higher efficiency technologies− Access to the grid and guaranteed buyback rates− Requirements for new power stations to consider cogeneration if feasible− Information programmes− Obligations to jointly produce heat and power− Voluntary agreements

Typical coal-fired power stations operate at 30-45% efficiency, while a modern combined cycle gas turbinestation can reach efficiencies close to 60%. However, cogeneration plants, which capture and use wasteheat from electricity production, can reach efficiencies of 70-90%17. As cogeneration is often based on co-location of load and generation, these plants can also minimise transmission losses. So, cogeneration hasthe potential for significant economic efficiency as well as emission reduction benefits. As manycogeneration facilities operate on natural gas or renewable fuels, they often have further emissionadvantages relative to centralised generation.

There are two main applications of cogeneration - industrial applications and district heating. Withincreasingly smaller cogeneration technologies available, “industrial” applications can include smallcommercial as well as industrial sites. However, to maximise the efficiency of the technology, it isimportant to find sites with appropriate matching of heat and electricity demands. It is also important that,where businesses control their own energy supply, this does not lead to lax energy management due to aperception that the energy is free. Energy market reforms which increase options to sell excess electricityinto the grid help to alleviate this problem, as the opportunity cost of wasted energy is made more clear.

In order to use cogeneration effectively for district heating, it is necessary to have access to a centralisedheat distribution network. This is often lacking and can be an impediment to further growth of thiscogeneration application. Gas-based cogeneration can also emit significant amounts of NOX, which canlead to local air quality problems, especially if the cogeneration site is in a densely settled urban area.

Once again, the variety of potential situations makes generic cost assessment of this approach difficult.However, unlike power station operators for whom generation option choice is core business, manysmaller potential cogeneration users may be unfamiliar with the technologies available to them, or even ofcogeneration as an option. Therefore, there may be considerable scope for no regrets and low costabatement through promotion of cogeneration opportunities. As cogeneration is often based on biomass asan energy source and leads to reduced transmission losses, cogeneration can also be part of an integratedapproach to reducing emissions from energy supply.

In considering measures to promote greater use of cogeneration, issues to be considered include:

17 Although the electric component on its own may have lower efficiency than some alternatives.



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Are estimates available of the full potential for cogeneration in energy supply?

Are energy users non-rational in their level of takeup of cogeneration?

3.3.2 Improving combustion efficiency in power plants

Actions taken by Annex 1 countries to promote greater combustion efficiency in power plants include:− Support for R&D for higher efficiency technologies− Energy market reform to promote greater competition and increase pressure for efficiencies− Efficiency standards for fossil fuel plants− Voluntary agreements− National targets− Subsidies for investment in high-efficiency plant

Improvements to the efficiency of power stations happens in three major ways - basic technology choice,load management, and technical adjustment. New technologies are constantly being developed that cansubstantially improve operating efficiencies. For example, development of low capital cost, modulartechnologies for combined cycle gas turbine plants have allowed widespread and growing adoption of thishighly efficient generation option. Ongoing research into areas such as integrated gasification combinedcycle technology could lead to economical applications of this technology which would greatly increasecombustion efficiences and reduce emissions from coal-fired power.

There has been steady improvement in overall generating technology. In Japan, overall thermal efficiencyincreased from 24% in the mid-1950s, to 37% in the mid-1980s and 39% in the mid-1990s (Japan 2dNational Communication). Most of this improvement is due to changes in underlying technologies.

Load management is important to plant performance. Many plants operating at low load factors will be farless efficient and produce far more emissions than fewer stations at higher loads, all other things beingequal. Similarly, peak shifting to ensure a more steady flow of load over the course of the day, cancontribute to overall system performance. Policies to address these issues are generally considered as partof demand-side measures.

Once the boilers and turbines for a power station have been installed, it is difficult to substantially alter thebasic performance of that station without significant new investment. However, there are often relatively“minor” changes that can be made to the operation of the plant, such as reductions in own use (about 8% ofOECD electricity generation in 1996), reblading, improved temperature and airflow management, etc.Together, these might improve the efficiency of an existing plant by a few percent. Improvement of theoperating efficiency of zero-emission plants, such as nuclear and hydro, can be achieved through similarapproaches, providing an effective increase in the shares of these fuels and deferring the need for newplant. Where this potential new plant would be fossil-fueled, this leads directly to emission reductions.

While developments in underlying technology will deliver the largest gains in the long term, attention toload management and incremental improvements to existing plant can play an important role in Kyototime-frames. If, for example, 80% of 2010 generating capacity already exists, a 1% improvement in theoperation of existing plant will achieve as much as a 4% improvement in new plant. However, significantchanges in existing plant can generally be made only at times of major refurbishment, which areinfrequent. Therefore, attention to timing is necessary to ensure cost-effectiveness of such approaches.



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Energy market reform is likely to deliver improved signals to improve efficiency of generation, ascompetitive pressures will force more careful attention to potential waste. However, without directincentives of some sort to account for environmental benefits, companies are unlikely to go beyond “noregrets” approaches. If market reform also leads to incentives for extension of life of old plant, this slowerturnover of capital stock to cleaner new technologies could outweigh the emission benefits of reforms.

Fuel cell technology, which converts chemical energy directly to electricity, can be considered anemerging, highly efficient “combustion” technology. As well as efficiency improvements, fuel cells canoffer modularity, reliability, cogeneration potential, reduced air emissions, and co-location advantages thatmake them attractive energy sources. The emissions performance of fuel cells relies on the fuel used(including its lifecycle emissions) - for example, while the process of producing electricity from fuel cellsfrom hydrogen gives off no greenhouse or other polluting emissions, the process of producing hydrogencan be highly energy intensive. The main limitation on use of fuel cells currently is cost, however, andconsiderable research, much of it government funded, is developing ways to reduce the costs of thistechnology.

In considering measures to promote improved combustion efficiency, issues to be considered include:

What should be the relative focus of measures in this area on new versus existing plant? Howshould support be allocated to leading edge “breakthrough” technologies versus steadyimprovements to “standard” technologies?

As even efficient coal-based technology will produce greater emissions per kWh than average gas-based technology, what role should investment in “cleaner coal” technologies play in greenhouseabatement?

Do fuel cells offer an opportunity to fundamentally alter the way electricity is produced andgreatly reduce greenhouse and other environmental emissions?

3.3.3 Reducing transmission and distribution losses

Actions taken by Annex 1 countries to reduce transmission and distribution losses include:− Energy market reform to promote greater efficiencies and cost-reflective transmission pricing− Voluntary agreements− Efficiency standards and labelling for transformers− Gold-lining of gas distribution systems to reduce leakage

In 1996, about 1% of natural gas and 7% of electricity generation was lost in transmission and distributionin the OECD, although this varied considerably amongst countries (Table 8). Differences in percentagelosses reflect a number of factors including geography and the nature of generation, as well as efficiency oftransmission infrastructure. However, higher figures indicate there may be greater potential for savingsthrough efficiency improvements. While it is impossible to reduce these losses to zero, any reductions willeffectively enhance energy supply without increasing emissions, so can play a role in emissions abatement.The two basic approaches to reducing emissions are technical and operational.

Technical improvements, such as transformer and compressor upgrades, will be supported through thegreater competition of energy market reform. However, as with other market-driven efficiencies,companies will only undertake such improvements as long as they are profitable. In the absence ofexternality pricing, this will not equal the socially optimal level.



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The second approach to improvements is to reduce the distance electricity and gas travel by bettermatching of the location of load and generation. A key to this is again energy market reform. If suchprocesses deliver adequate signals to indicate the costs to generators and consumers of locational choice,there will be incentives to reduce losses. However, both generators and most consumers are immobile inthe short term, so it will take time for this to have a significant effect. And, again, incentives will only goas far as financial interest in the absence of specific greenhouse policies. As cogeneration generallyreduces transmission losses very substantially, promotion of this technology has synergies with increasedtransmission efficiencies.

In considering measures to promote greater use of cogeneration, issues to be considered include:

Should performance benchmarks of transmission performance be developed to assess performancewithin and among countries?

Table 8 - Losses from electricity distribution in 1996% of generation lost in

transmission anddistribution

Turkey 17%Mexico 15%Poland 13%Hungary 13%New Zealand 11%Portugal 10%Iceland 9%Spain 9%Ireland 9%United Kingdom 8%Czech Republic 8%Canada 8%Norway 7%Greece 7%France 7%Sweden 7%Denmark 7%United States 7%Switzerland 7%OECD Weighted Average 7%Australia 7%Italy 6%Austria 6%Belgium 5%Korea 5%Germany 5%Finland 4%Japan 4%Netherlands 3%Luxembourg 3%Source: IEA Energy Statistics



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3.4 Some lessons from experience

3.4.1 Issues Related to Specific Approaches

Governments operate in widely differing economic, social and physical environments, which requireconsideration in developing national policies. However, based on experiences to date, there are somegeneral observations that can be made in relation to greenhouse abatement actions in the SESS. In relationto the policies countries have adopted to date:

• There is a wide range of regulatory and financial mechanisms to promote the growth of renewablesenergy. In general, these programmes appear to recognise that promoting renewables is not a pure“no regrets” measure.

• There also appears to be relatively wide government support (regulatory and financial) forcogeneration/CHP. However, it is not clear that these measures in general move beyond noregrets, rather than attempting to deal with institutional difficulties in reaping the economic andenvironmental benefits of these technologies.

• Nuclear energy continues to be heavily subsidised through large government R&D spending.While this spending is focused in a small number of countries, its magnitude means thatrenewables continue to receive more than half of government energy R&D spending.

• In relation to other approaches (fuel switching, efficiency of generation and transmission anddistribution), governments seem more reluctant to move beyond “no regrets” policies. The mostcommon measure to implement these approaches is energy market reform, where greenhouseoutcomes are not the primary objectives. In many cases, these approaches do appear to yieldgreenhouse benefits on the supply side. However, it is uncertain that reliance on such mechanismswill be enough to achieve the Kyoto target, especially as these approaches are the only ones toaddress emissions from existing plant, which will dominate total energy use and emissions in2008-12. Also, it is important to recognise that reform processes will vary in their environmental(and economic) impacts, and in some cases greenhouse emissions may rise. While reform candeliver incentives for efficiencies, fuel switching and cogeneration, there is no guarantee that itwill do so, or to what extent. Greenhouse policy-makers have an interest in the pace and nature ofenergy market reform given its potential impacts on greenhouse emissions.

Overall, there appears to be a heavy focus on making reductions through investments in new plant.However, the relatively small addition to new plant to the year 2008 means that more attention to reducingemissions in existing plant may be required. Table A (in the Participant’s guide at page 3) indicates someconsiderations that will affect choice amongst alternative approaches. For each of the approachesdiscussed in this paper, this table shows:

Technical Emissions abatement potential in the Kyoto time frame (i.e. to 2012) and the long term.This reflects both levels of savings from individual application of these approaches and potentialpenetration rates.

Rationale for government involvement - apparent reasons for governments to intervene in variousways to support these approaches to reducing emissions. While greenhouse emissions are clearly a



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concern, there are also many other relevant issues, many of which are essentially “ancillarybenefits” of greenhouse reduction policies.

Abatement cost - the cost of promoting this approach beyond business-as-usual relative to thesavings achieved. Because of many location- and technology-specific factors, this can only bebroadly indicative.

Other considerations - other factors that could affect choices to use this approach as a greenhouseabatement measure. Cost constraints are not included, as they are an element of abatement costanalysis.

3.4.2 General Issues

There are also some general issues that arise from consideration of the major abatement strategies:

Assessing effectiveness

• Business-as-usual trends generally include some positive greenhouse abatement actions already,especially in relation to penetration of natural gas. Any measures will need to achieve savingsbeyond this to move away from BAU toward achievement of Kyoto objectives.

• The cost-effectiveness of many measures falls if gas is assumed to play a greater role in BAU,since the emissions savings will generally be smaller. Targeting mitigation or replacement ofexisting sources with the highest emissions intensity may assist effective abatement strategies.

Integrating economic and environmental objectives

• Comprehensive measures such as taxes and tradable permits can generally give incentives for leastcost abatement. Where market distortions and other reasons lead to adoption of sector-specificmeasures, it is important to identify the reason for using such measures, and ensure the measuresaddress these reasons directly.

• Given the challenges of meeting Kyoto targets, maintenance of emission-increasing subsidies tofossil fuel use appear unsustainable. Reform of such subsidies offers considerable potential for noregrets emissions reductions.

Time frames for change

• Electricity generation is dominated by long-term investments. This has a number of implications:− Action to achieve significant savings beyond business-as-usual will need to start immediately

if the Kyoto commitments are to be met.− Any actions will need to provide incentives for investment in lower emissions technologies.

These incentives will need to be of sufficient size up-front to make these investmentsattractive, or there must be relative certainty that on-going incentives will continue for sometime.

− Actions to reduce emissions from new plant will need to achieve significant emissionsintensity improvements if they are to contribute significantly to meeting Kyoto commitments,since only a small portion of total plant in 2008-12 is affected.



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− Governments should already be considering their post-2012 emissions profile and potentialemission reduction objectives.

• Over short to medium time frames, improvements to existing plant may achieve greater savingsthan changes to new plant. However, this can require expensive premature retirement of capital ifmeasures are not timed carefully.

Relationships between measures

• Many alternative approaches are competing for the same policy space. For example, renewables,nuclear and gas are all potential fuel sources with abatement potential. If they are all beingpromoted for the relatively small portion of total plant to be built between now and 2010, there aresignificant limits on what can be achieved by any of the options. Current large reserve generationcapacities, possibilities for repowering of existing plants and better use of existing capacity astrade increases all may exacerbate this problem. Governments need to consider the interactionsbetween alternative approaches, and evaluate whether particular options are more cost-effective inparticular niches.

• Where a mix of sectoral measures is adopted, it is important that this mix be coordinated toachieve the desired outcome. For example, R&D support may be ineffective withoutcommercialisation incentives, but commercialisation incentives for technology that is not yetsufficiently developed will be wasteful. Similarly, incentives to use certain fuels will beineffective if distribution infrastructure is not yet in place. And to better ensure greenhousebenefits from energy market reform, it will be important that reform of natural gas and electricitymarkets move in parallel.



References

Allen Consulting Group (1998), Energy Market Reform and Greenhouse Gas Emission Reductions, Reportto the Australian Department of Industry, Science and Tourism

European Commission Directorate-General for Energy (DGXVII) (1996), Energy in Europe:European Energy to 2020; A Scenario Approach, Luxembourg

European Commission (1995), ExternE: Externalities of Energy, Luxembourg

Echávarri, Luis E. (1998), “Nuclear Power and Global Warming”, Presentation to the 31st JAIF AnnualConference, Tokyo.

Ellis, J and Karen Treanton (1998), “Recent trends in energy-related CO2 emissions”, Energy Policy, Vol.26, No. 3, pp. 159-166.

Energy Information Administration (1999), Annual Energy Outlook 1999 Model Results, US EIA .

European Commission (1995), ExternE: Externalities of Energy, Report for DGXII, Luxembourg.

IAEA (1998), Nuclear Power Reactors in the World, Vienna

IEA (1999), “Review of Nuclear Power: Historical Patterns”, IEA/SLT(99)2

IEA (1998a) World Energy Outlook 1998 Edition,

IEA (1998b) Renewable Energy Policy in IEA Countries: Volumes I and II,

IEA (1998c), Benign Energy? The Environmental Implications of Renewables, OECD, Paris

IEA GHG R&D Program, Greenhouse Gas Emissions from Power Stations

IEA/NEA (1998), Projected Costs of Generating Electricity: Update 1998, OECD, Paris.

Interlaboratory Working Group on Energy-Efficient and Low-Carbon Technologies (1999), Scenarios ofU. S. Carbon Reductions: Potential Impacts of Energy-Efficient and Low-Carbon Technologies by 2010and Beyond

McDonald, D, John Donner and Andrei Nikiforuk (1996), “Full Fuel Cycle Emission Analysis for ElectricPower Generation Options and Its Application in a Market-Based Economy , Presented at the ThirdInternational Conference on Carbon Dioxide Removal, September 9-11, 1996, Boston, MA, U.S.A.

OECD (1998), Improving the Environment through Reducing Subsidies, Part I: Summary and PolicyConclusions and Part II: Analysis and Overview of Studies, OECD Publications, Paris.

OECD (forthcoming), Taking Action Against Climate Change: Towards Efficient National Policies, Paris

Vera, Ivan, Evelyne Bertel and Geoffrey Stevens (1998), “Alternative Nuclear Paths to 2050” Proceedings



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of the Annual International Symposium of the Uranium Institute, London, 1998.

-----, First and Second National Communications of Annex I countries, and Indepth Reviews of NationalCommunications of various countries by the UNFCCC



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Annex - Questions on Individual Measures

Following are generic questions relevant to any greenhouse abatement measure. Speakers have been askedto address these questions in their presentations.

What is the current status of the measure (eg in place, in Parliament, in consultations withstakeholders, etc.)

What are the market imperfections that this initiative is designed to address? What are the designelements intended to address these? How has the measure performed in addressing theseimperfections?

What other measures were considered to achieve the same objective(s) and why were they notpursued?

Does the measure work in isolation, or is it part of a policy package? Is the measure supported byother measures or does it support them. Does it conflict with other policies and measures?

Is it expected that the measure will contribute to goals other than greenhouse abatement (e.g.reductions in air pollution, employment)? How important were these ancillary benefits inadopting the measure?

What are the administrative and economic costs of the measure? What emissions savings areexpected by different times?

What steps have been taken to monitor performance of the measure? Are there specificperformance benchmarks? How has the measure performed relative to expectations?

What have been the major barriers to implementation (especially unanticipated ones)? Whatmethods were used to solve these problems?

What is the expected future of this measure and other actions addressing the problem identified?

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