1ENERGYIn addition, wood stoves (where there is a great variation in technology by geographic
region) may have particularly high emissions rates of NMVOC due to their largely
inefficient combustion of fuel.
The NMVOC emissions from mobile sources are a function of the amount ofhydrocarbons passing unburnt through the engine. This depends on engine type, fuelused, use of post-combustion emission controls (e.g., catalytic converters) and driving
regime. The emissions are generally highest at low speeds and when the engine is idle.
Poorly tuned engines may have a particularly high output of hydrocarbon compounds.
NMVOC evaporative emissions from gasoline mobile sources should be accounted for
here.
The general method for estimating NMVOC can be described as:
Emissions = ∑ (EFab x Activityab)
where:EF
Activityab= Emission Factor (kg/TJ);= Energy Input (TJ);= Fuel type; and= Sector-activity.

Due to large differences in emission factors for various sectors, fuel consumption must be
allocated to the IPCC main activity groups.
Extensive NMVOC emission factor data are available for most of the fuel combustion
sources. The following default emission factors have been developed by the IPCC basedon the CORINAIR90 database, Radian (1990), US EPA (1995), the EDGAR Version 2.0
database, and National Communications to the FCCC. The aggregated emission factors
in this table allow a rough estimation of NMVOC emissions.

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TABLE 1-11
NMVOC DEFAULT (UNCONTROLLED) EMISSION FACTORS (IN KG/TJ)
Coal

NaturalGas

Oil

Energy Industries

5

5

5

50(b)

100(b)

50

Manufacturing Industries andConstruction

20

5

5

50

100

50

Transport

Aviation(c)Charcoal

Other Biomass
and Wastes(a)

50

Road

Other
Sectors

Wood/
Wood Waste

5

Gasoline

Diesel1500(d)200

Railways

20

200

Navigation

20

200

Commercial/Institutional

200

5

5

600

100

600

Residential

200

5

5

600

100

600

200

5

5

600

100

600

5

200

Agriculture/
Forestry/
Fishing

Stationary
MobileNote: These factors are considered as the best available global default factors to date.
(a) Includes dung and agricultural, municipal and industrial wastes.
(b) These factors are for fuel combustion in the energy industries. For charcoal production, please refer to Table 1-14, Default Non-CO2 Emission Factors for Charcoal
Production.
(c) The emission factor for aviation in the above table is for jet kerosene. The emission factor for aviation gasoline is 300 kg/TJ.
(d) These factors are the sum of combustion and evaporative emissions from gasoline use. The NMVOC emission factors for mobile sources from evaporation of gasoline
vary with the ambient temperature. In general, in the “warmer” countries the emission factors will be higher than in “colder” countries.

1.4.2.6

SULPHUR DIOXIDE (SO2) EMISSIONSFROM FUEL COMBUSTION

Sulphur dioxide is not a “greenhouse gas” but its presence in the atmosphere may
influence climate. SO2 can react with a variety of photochemically produced oxidants toform sulphate aerosols. The concentration of these particles is increasing due to theburning of fossil fuels which contain sulphur. Over limited regions of the northernhemisphere, the effect of these particles is comparable in size, although opposite in effect,
to that of human generated greenhouse gases up to the present time. Any effect ofsulphur dioxide emissions on climate change can be expected to be strongly regional incharacter - but studies of this with climate models need to be carried out (Houghton,1994). Although SO2 is not a direct greenhouse gas, it is an aerosol precursor and assuch, has a cooling effect on climate.
Anthropogenic SO2 emissions world-wide amount to 70-80 million tonnes per year
(Mt/y) (Vernon and Jones, 1993). This compares with natural emissions of 18-70 Mt/y
(IPCC, 1992). There is, however, a paucity of information on the relative contribution ofsulphur emissions arising from combustion, due to lack of detailed information on thesulphur level of the fuel consumed. More than 80 per cent of anthropogenic SO2 arises
from fuel combustion, with three-quarters of this arising from coal (Vernon, 1990). At
present an estimated 10 Mt/y of coal-related SO2 emissions are removed by flue-gas
desulphurisation technology world-wide (Ando, 1992).

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ENERGYThe general method for estimating SO2 can be described as:
Emissions = ∑ ( EFab x Activityab )where:EF= Emission Factor (kg/TJ);
Activity = Energy Input (TJ);a= Fuel type; andb= Sector-activity.
The emissions of sulphur oxides (SOx) are directly related to the sulphur content of thefuel, which for coal can vary from below 0.5 to over 10 per cent by weight. The majority
of coals currently in use are in the range 0.5 to 3 per cent. Generally the “southernhemisphere” coals contain less sulphur than “northern hemisphere” coals.
For fuel oil (including heavy fuel oil) sulphur content varies from 0.3 to over 5 per cent.
Lighter products may contain minimal sulphur (<0.3 per cent), whilst heavy fuel oil cancontain from up to 3-5 per cent sulphur. Currently the world average sulphur content of
crude oil is around 1.3 per cent, although there are considerable variations between
different sources (Vernon and Jones, 1993).
The sulphur content of gas is usually negligible.
The SO213 emission factors can be estimated as:

2 x (

s
100

) x

1
Q

EFSO2 [kg/TJ] =x 106 x

( 1 10 00 0- r ) x ( 1 01 00 0- n )where:
EF = Emission Factor (kg/TJ);
2 = SO2/S [kg/kg];s = Sulphur content in fuel [%];
r = Retention of sulphur in ash [%];
Q = Net calorific value [TJ/kt];
106 = (Unit) conversion factor; andn = Efficiency of abatement technology and/or reduction efficiency [%].
Sulphur appears in coal as pyritic sulphur (FeS2), organic sulphur, sulphur salts andelemental sulphur. Pyritic and organic sulphur account for the vast majority of sulphur incoal and both types are responsible for SOx formation. The sulphur is released when thecoal is burnt, mainly oxidised to SO2. Usually less than 1-2 per cent of the total sulphur isreleased as SO3.

13 Sulphur dioxide (SO2 + SO3 expressed as SO2 mass equivalent).

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TABLE 1-12
SAMPLE AND DEFAULT VALUES OF SULPHUR CONTENT ( S ) IN FUEL
Default
value(a)[%]CORINAIR 90(b)
range
[%]

- low S0.5

≥ 0.001- medium S

1.5-- high S

3.0≤ 16.1- low S1.0

≥ 0.001- medium S

3.0(c)-- high S

4.0

≤ 4.0

Light fuel oil/diesel - low S

0.3≥ 0.14- high S

1.0

≤ 1.0

0.3

0.1-1.0

Fuel (IPCC grouping)

Coal

Heavy fuel oil

Diesel (road)
Gasoline (road)

0.1

0.012 - 0.15

Jet kerosene

0.05

0.0001-0.3(d)Oil shale

1.5(1.3-1.7)(e)NAV

Natural gas

negligible

NAV

Municipal waste

0.003

0.003

Industrial waste

0.2

0.200 - 1.000

Black liquor

1.50.004 - 8.09

Fuelwood

0.2

0.001-0.06

Other biomass< 0.030.001 - 0.800(a) To be used only if no better information is available.
(b) Fuels used in CORINAIR 90 inventories in the Czech Republic, Denmark, France,
Hungary, Italy, the Netherlands, Poland and the Slovak Republic.
(c) The medium value refers to the default for marine bunkers.
(d) Values reported in literature.
(e) Values from Estonia.

During fuel combustion, part of the sulphur is retained in ash. The sulphur retention inash for coal ranges from 5 to 60 per cent, (usually less than 10 per cent). The proportion
depends upon the composition of the ash. The sulphur retention in ash for liquid fuelsand biomass is minimal and can be disregarded.

Default Values for the Sulphur Retention (r) in Ash [%]Hard coal

5

Brown coal30

If abatement technologies for SOx emissions reduction are used, the estimated emission
factors for SO2 should be correspondingly reduced. Reduction efficiency values fordifferent types of abatement technologies may vary between 45 and 95 per cent (Rentz,
et al., 1992).

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1.4.3 Biomass Data
The tables below provide data for use within the Reference Approach or for the
calculation of all emissions by source categories using the methods described in
Sections 1.4.1 and 1.4.2.

TABLE 1-13
ENERGY CONTENT OF BIOMASS FUELS: DEFAULT NET CALORIFIC VALUES
Biomass Fuel

Moisture Content
Typical Net(% mcwb)(a)Calorific Value(b)(MJ/kg)Reference

BASIC BIOFUEL TYPES:
Fuelwood(c)2015Hall et al. (1994b)

Charcoal

30

Hall and Mao (1994a)

Dung

12

GOB (1987)

Bagasse8

Leach and Gowen (1987)

Agricultural Waste

50

15

Leach and Gowen (1987)

Other Waste

11

US EPA (1995)

EXAMPLES OF SPECIFIC BIOFUELS:
Wood
Wet, freshly cut
Air-dry, humid zone
Air-dry, dry zone
Oven-dry

40
20
15
0

10.9
15.5
16.6
20.0

Leach and Gowen (1987)
Leach and Gowen (1987)
Leach and Gowen (1987)
Leach and Gowen (1987)

Charcoal5

29.0

Leach and Gowen (1987)

BagasseWet
Air-dry

50
13

8.2
16.2

Leach and Gowen (1987)
Leach and Gowen (1987)

Dung cakes (dried)

12

12.0

Leach and Gowen (1987)

OTHER AGRICULTURAL RESIDUES:
Coffee Husks

12

16.0

Leach and Gowen (1987)

Ricehulls (air-dry)

9

14.4

Leach and Gowen (1987)

Wheat straw

12

15.2

Leach and Gowen (1987)

Maize (stalk)

12

14.7

Leach and Gowen (1987)

Maize (cobs)

11

15.4

Leach and Gowen (1987)

Cotton gin trash

24

11.9

Leach and Gowen (1987)

Cotton stalk

12

16.4

Leach and Gowen (1987)

Coconut husks

40

9.8

Leach and Gowen (1987)

Coconut shells

13

17.9

Leach and Gowen (1987)(a) mcwb : moisture content weight basis.
(b) Typical values to be considered as rough approximations.
(c) Assuming air dry wood.

Values for estimating the amount of carbon released through charcoal production andconsumption, the wood-to-charcoal factor, are stated to be between 4 and 8. If no local
information is available, 6 kg of wood input per kg of charcoal may be used as default

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ENERGY(FAO, 1990). In many developing countries, there are usually no cross checks on thequality of charcoal. Consequently, substandard charcoal will be passed on as charcoal.
Typical wood to charcoal conversion factors in many developing countries would range
from 2.5 to 3.5 and rarely beyond this. This also implies that the carbon fraction of
charcoal is around 0.6 to 0.7. Default emission factors related to the production of
charcoal are presented in the Table I-14
TABLE I-14
DEFAULT NON-CO2 EMISSION FACTORS FOR CHARCOAL PRODUCTION(IN KG/TJ)
CompoundDefault Emission Factor
Default Emission Factor(kg/TJ of Wood Input)(a) (kg/TJ of Charcoal Produced)

CH4

300

1000

N2 O

NAV

NAV

NOx

5

10

CO

2000

7000

NMVOC

600

1700

SO2

NAV

NAV

(a) Assuming 1 kg charcoal is produced from 6 kg wood and the energy content for wood andcharcoal is 15 and 30 MJ/kg respectively, 1 TJ charcoal produced is equivalent to 3 TJ wood
input.

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1.5

Detailed Methods (Tiers 2 and 3) for Fuel
Combustion
1.5.1 Overview
Identification and quantification of greenhouse gas emissions by source category andeconomic sector, together with a sound understanding of plant combustion conditions,are essential for the study of abatement procedures and the formulation of abatement
policy options. Equally, assessment of the effects of emissions on the atmosphere andclimate requires detailed data on the magnitude and spatial distribution of pollutant
emissions. Both sets of requirements are served by the estimation of emissions fromcombustion activities categorised by plant types at a level of detail for which an emission
factor can be reasonably narrowly specified. Studies of the products of combustion frommany types of plant under different operating conditions have resulted in a growing
database of emission factors linking the emission rate to the activity. Estimation
methodologies using these emission factors are described and discussed in this section.
In what follows, the emission sources are grouped into stationary and mobile sources andrepresentative emission factors for them are assembled for use in a simple formula
common to the majority of cases. The distinction between Tier 1 methods and those ofTiers 2 and 3 rests mainly on the reliance of the first on widely available fuel supply data
which, by its nature, takes no account of the combustion technology to which the fuel isdelivered. Distinguishing between Tiers 2 and 3 is less easily done as there is a steadily
increasing degree of refinement and detail in the emissions estimation process as themethods are developed from one tier to another. However, Tier 2 methods may be
regarded as those dividing fuel consumption on the basis of sample or engineeringknowledge between technology types which are sufficiently homogenous to permit theuse of representative emission factors. Tier 3 methods generally estimate emissions from
activity figures (kilometre travelled or tonne-kilometre carried, not fuel consumption) andspecific fuel efficiency or fuel rates or, alternatively, using an emission factor or factors
expressed directly in terms of a unit of activity.
A new methodology, developed from that used by CORINAIR, has been introduced forthe estimation of emissions from aircraft. Revised emission factors are also given foremissions from many types of stationary combustion and road transport in the UnitedStates and Europe.
Estimating CO2
It follows from the arguments given above for the construction of detailed emission
estimates that a country will also benefit from the estimation of CO2 emissions in parallelwith the calculation of non-CO2 inventories despite the existence of Tier 1 methods forCO2 estimation. The Overview to this Chapter also emphasises this point. Most of thetables of emission factors for mobile sources, but few of the tables for stationary sources,
have figures for CO2. In cases where CO2 emission factors are not given the carbon
emission factors provided for the fuel types listed for the Tier 1 methods will suffice. If
different fuel qualities are used in different applications national experts may wish to vary
the emission factors accordingly.
Where CO2 emission factors are given in this Chapter they include all carbon based
molecule emissions from the process. This ensures that CO2 totals constructed bysumming the results of the detailed estimation of emissions (the “bottom-up” approach)

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will be comparable with the IPCC Reference Approach described under Tier 1 methods
above. The Reference Approach provides a simple transparent and verifiable means ofaccounting for all of the carbon in fuels which could be emitted to the atmosphere.
Because of the complexity of covering all sources of fuel combustion and obtaining therelated data it does not automatically follow that summing emissions from the many
detailed sources will result in a figure close to that obtained from the Reference
Approach. Consequently, verification of CO2 totals against the Reference Approach is an
obligation of the IPCC reporting system.
Use of carbon emission factors based on the fuel’s carbon content also implies that
adjustments may be needed (depending on the combustion process under consideration)
for any carbon unoxidised. Carbon remaining unoxidised after combustion is discussed in
Section 1.4.1.1. Where emission estimates are prepared by plant type the general
information given in the section cited may be used when more specific carbon unoxidised
factors are not available. At the level of process detail implicit in Tiers 2 and 3, quantities
of fuel combusted should be known or fairly well estimated and quantities delivered forthe manufacture of non-energy products identified and excluded. Where this is not thecase estimates of carbon stored in manufactured products will need to be made incollaboration with national experts preparing estimates of emissions from Industrial
Processes to ensure that there is no double counting of emissions.

DATA SOURCES
National experts working on detailed emission of non-CO2 GHGs (particularly theindirect gases) and SO2 should consult the extensive literature on emission factors andother estimation procedures which has been developed by other inventory programmes
outside of the framework of the IPCC/OECD/IEA programme. These data generally
contain more technology detail, and are further broken down by size of the various
technologies. For mobile sources, data generally contain more vehicle and control
technology detail, and are further broken down by operating conditions (e.g., catalyst
vintages, driving cycles). The nature of these control assumptions should be known andcarefully matched with actual conditions in the country when selecting the specific factors
to be used.
Some key examples of data sources are:

1.48

•

Default Emission Factors Handbook (European Environment Agency Task Force,
Bouscaren, 1992)•

CORINAIR Working Group on Emission Factors for Calculating 1990 Emissions
from Road Traffic, Volume 1: Methodology and Emission Factors (Eggleston, et al.,
1992)

•

CORINAIR Working Group on Emission Factors for Calculating 1990 Emissions
from Road Traffic, Volume 2: COPERT Model, Users Manual (Andrias, et al., 1992)•

Atmospheric Emission Inventory Guidebook (Joint EMEP/CORINAIR, European
Environment Agency, 1996)•

US EPA's Compilation of Air Pollutant Emissions Factors (AP-42), 4th Edition 1985,(US EPA, 1985a and 1985b), 5th Edition 1995 (US EPA, 1995) and Supplement F,(US EPA, 1993b)

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ENERGY•US EPA's MOBILE5a (US EPA 1994a). Contact Terry Newell, US EPA Office ofMobile Sources, 2565 Plymouth Road, Ann Arbor MI 48105, USA; tel: (313) 6684462, Email: Newell.Terry@epamail.epa.gov or access the latest information on
mobilesources
on
the
world
wide
web
at
http://www.epa.gov/OMSWWW/omshome.htm.

•

Criteria Pollutant Emission Factors for the 1985 NAPAP Emissions Inventory(Stockton and Stelling, 1987)•

Proceedings of the TNO/EURASAP Workshop (TNO, 1993)•

EMEP and CORINAIR Emission Factors and Species Profiles for Organic
Compounds. (Veldt, 1991)•

Transport Statistics for Europe (UN ECE, 1989)•

World Road Statistics (International Road Federation, 1990)•

Other compilations of emission factors include-

Netherlands
NorwayGermany

Bakkum, et al., 1987, Okken, 1989
Statens forurensningstilsyn, 1990
Brieda and Pakleppa, 1989, Fritsche, 1989, Rentz et al.,
1988,
Walbeck, et al., 1988
JAERI, 1988
Eggleston and McInnes, 1987

-

Japan
United Kingdom
UNEP Country Studies
US Country Studies, US CSP, 1996
National Communications to the FCCC

1.5.2 Stationary Combustion
1.5.2.1

OVERVIEWThis section considers emissions of NOx, N2O, CO, CH4, SO2 and NMVOCs fromstationary combustion plant. Estimation of CO2 emissions at the level of detail of Tiers 2
and 3 is described in Section 1.5.1.
The section focuses on emissions from the combustion of commercial fuels, which include
virtually all fossil fuels and biomass fuels traded commercially and used in large combustion
plants. Non-CO2 emissions from combustion of biomass are estimated in exactly thesame manner as fossil fuel combustion emissions.14.
Emissions of non-CO2 greenhouse gases across activities (sectors and subsectors) will depend
upon fuel, technology type and pollution control policies. Emissions will also vary with thesize and vintage of the combustion technology, its maintenance, and its operation. Most of acountry’s NOx emissions arise from stationary fuel combustion. As defined here (i.e.,
excluding "traditional" small scale use of biomass), this category generally contributes a smaller
but still significant share of national emissions of CO and NMVOC, and, to a lesser extent, of
N2O and CH4. These two gases are nonetheless discussed in some detail because of theirpriority status within the IPCC/OECD/IEA programme.

14 See Section 1.4.3 for a discussion of CO

2 emissions from biomass combustion.

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A section on SO2 has been added to the Tier 1 methodology. In the more detailed Tier 2
approach the same basic formula should be applied to more detailed fuel information.

1.5.2.2

RECOMMENDED METHODOLOGY

General Method
Estimation of emissions from stationary sources can be described using the following basic
formula:Emissions = ∑ (EFabc x Activityabc)
where:
EF = Emission Factor (kg/TJ);
Activity = Energy Input (TJ);
a = Fuel type;b = Sector-activity; andc = Technology type.
Total emission for a particular country is the sum across activities, technologies and fuelsof the individual estimates.
Emission estimation is based on at least three distinct sets of assumptions or data:
1) emission factors; 2) energy activities; and 3) relative share of technologies in each of
the main energy activities. Sources of the emission factors and energy activity data thatare relevant internationally are described briefly below and suggestions on appropriate
use of such data are made.
Technology share or technology splits for each of the various energy activities are needed
at least on a national level for non-CO2 greenhouse gas estimation since emission levels
are affected by the technology type. Unfortunately, there is no complete internationalsource of data on technology splits and, as a result, each country will need to develop its
own technology splits for each energy activity.
The main steps in the inventory method can be summarised as follows:

1.50

1

Determine the source and form of the best available, internationally verifiable,
national (or sub-national) energy activity data.

2

Based on a survey of national energy activities, determine the main categories ofemission factors.

3

Compile best available emission factor data for the country, preferably from nationalsources. If no national sources are available, select from the options described here.
Selection among the options should be based on the similarity of the country to thesource of original measurements for types of technology and operating conditions
across main energy activities. The selection should also consider the extent towhich control technologies may be in place and requires the ability to clearly
separate and understand control policy assumptions that may be embedded in theemission factor data.

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4

Based on the form of the selected emission factors, identify the technology
categories to be used in the national inventory.15

5

Using these assumptions on technology categories, develop estimates for each of thegreenhouse gases for each main activity.

6

Sum the individual activity estimates to arrive at the national inventory total for eachof the greenhouse gases.

Technology Splits for Energy Data
National data or assumptions on the technology shares of each of the main source sector
categories which have been identified as important in each country are necessary tocreate the linkage between national energy balances and the emission factors. Again, thismay be based on "bottom-up" data collection at as detailed a level as individual sources,
or it may be more of a “top-down” allocation based on statistical sampling, or engineering
judgement. The objective is to match up fuel use, by fuel type, with specific technologies
or classes of technologies, for which credible emission factors for non-CO2 gases can beprovided.
Emission Factor Data
Emission factors for all non-CO2 greenhouse gases from combustion activities vary tolesser or greater degrees with:•

fuel type•

technology•

operating conditions•

maintenance and vintage of technology

and so represent the average emission performance of similar technologies.
They are therefore technology specific, but may still represent a wide distribution of
possible values because of the influence of the other three factors above. When available,
the standard deviation of the emission factor should be used to show the range ofpossible emission factors, and hence emissions, for each particular energy activity.16

1.5.2.3

EMISSION FACTORS

Some tables of representative emission factors for NOx,17 CO, CH4, N2O and NMVOCs
by main technology and fuel types (based on Radian, 1990) were presented in the
preliminary methodology manual (OECD, 1991) distributed by the IPCC. This information isstill useful in showing the range and variation of sources and emission rates, and it is

15 This may also require assumptions about the control technologies in place.
16 Unfortunately, the standard deviation of emission factors is rarely reported withemission factor data. One study shows that when considered, variation of emission
factors within an energy activity vary widely, from 20 to more than 50 per cent (Egglestonand McInnes, 1987).
17 The convention in this document is that NOx emissions from fossil fuel combustion
are expressed on a full molecular basis assuming that all NOx emissions are emitted as
NO2.

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reproduced in Tables 1-15 to 1-19 for the major categories.18 All factors are expressedon a kilograms per terajoule of energy input basis (unless stated otherwise) and arestated on a full molecular weight basis. These data are taken from Radian (1990) andshow uncontrolled emission factors for each of the technologies indicated. Theseemission factor data therefore do not include the level of control technology that might
be in place in some countries. For instance, for use in countries where control policies
have significantly influenced the emission profile, either the individual factors or the final
estimate will need to be adjusted.
It may be necessary to make adjustments to "raw" emission estimates to account forcontrol technologies in place. Alternative control technologies, with representative
percentage reductions, are shown in Tables 1-20 to 1-23 (Radian, 1990) for the main
control technologies applicable to each sector. These tables reflect technologies in use
for large stationary sources in OECD countries. Preliminary indications are that, in therest of the world, control technologies are not typically used (see OECD/IEA, 1991).
These data should be used in combination with the uncontrolled emission factors todevelop a "net" representative emission factor for each of the technologies to be
characterised in the national emission profile; alternatively, the emission estimate for eachtechnology could be adjusted downward according to the indicated percentage reduction
and the estimated penetration of the control technology.
Table 1-24 provides the fuel property assumptions upon which the Radian data are based.
The emission factor data in these tables are provided primarily for illustrative purposes.
These factors could be used as a starting point or for comparison by national experts
working on detailed "bottom-up" inventories. More detail on current emission factors
and references is presented in the section on Data Sources.
No emission factors for SO2 are presented in Tables 1-15 to 1-19. These emission
factors should be estimated based on the sulphur content of the fuels (see Section 1.4.2.6,
Sulphur Dioxide Emissions from Fuel Combustion).
In many countries, biomass is used in traditional, small-scale facilities and open stoves.
Emission factors presented in Tables I-16, 1-18 and 1-19 are for industrial combustion
and large-scale facilities.

18 Note: several printing errors occurred in the 1995 Guidelines.

These have beencorrected here.

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ENERGYTABLE 1-15
UTILITY BOILER SOURCE PERFORMANCE
Emission Factors (kg/TJ energy input)
Basic Technology

Configuration

CO

CH4

NOx

N 2O

NMVOCsCoal
Pulverised Bituminous Combustion

Dry Bottom, wall fired

9

0.7

380

1.6

NAV

Dry Bottom, tangentially fired

9

0.7

250

0.5

NAV
NAV

Wet Bottom

9

0.9

590

1.6

Bituminous Spreader Stokers

With and without re-injection

87

1.0

240

1.6

NAV

Bituminous Fluidised Bed Combustor

Circulating Bed

310

1.0

68

96

NAV

Bubbling Bed

310

1.0

270

96

NAV

Bituminous Cyclone Furnace

9

0.2

590

1.6

NAV

Anthracite Stokers

10

NAV

160

NAV

NAV

Anthracite Fluidised Bed Combustors

5.2

NAV

31

NAV

NAV

Anthracite Pulverised Coal Boilers

310

NAV

NAV

NAV

NAV

Pulverised Lignite Combustion

Dry Bottom, tangentially fired

NAV

NAV

130

NAV

NAV

Dry Bottom, wall fired

45

NAV

200

NAV

NAV

Lignite Cyclone Furnace

NAV

NAV

220

NAV

NAV

Lignite Spreader Stokers

NAV

NAV

100

NAV

NAV

Lignite Atmospheric Fluidised Bed

2.8

NAV

63

42

NAV

Normal Firing

15

0.9

200

0.3

NAV

Tangential Firing

15

0.9

130

0.3

NAV

Normal Firing

16

0.9

220

0.4

NAV

Oil
Residual Fuel Oil/Shale Oil
Distillate Fuel Oil

16

0.9

140

0.4

NAV

Distillate Fuel Gaseous Turbines

Tangential Firing

21

NAV

300

NAV

NAV

Large Diesel Fuel Engines >600hp (447kW)

350

4.0

1300

NAV

NAV

Boilers18

0.1(a)

250

NAV

NAV

Large Gas-Fired Gas Turbines >3MW

46

6*

190

NAV

NAV

Large Dual-Fuel Engines

340

240

1300

NAV

NAV

Natural Gas

Municipal Solid Waste (MSW)
Mass Burn Waterwall Combustors
MSW - Mass Feed(a)

22

NAV

170

NAV

NAV

98

NAV

140

NAV

NAV

Source: US EPA (1995).
(a) Adapted from Radian, 1990.

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual

1.53

ENERGY

TABLE 1-16
INDUSTRIAL BOILER PERFORMANCE
Emission Factors (kg/TJ energy input)
CO

CH4

NOx

N 2O

NMVOCsBit./Sub-bit. Overfeed Stoker Boilers

110

1.0

130

1.6

NAV

Bit./Sub-bit. Underfeed Stoker Boilers

190

14

170

1.6

NAV

Bit./Sub-bit. Hand-fed Units

4800

87

160

1.6

NAV

Dry Bottom, wall fired

9

0.7

380

1.6

NAV

Dry Bottom, tangentially fired

9

0.7

250

0.5

NAV
NAV

Basic Technology

Configuration

Coal

Bituminous/Sub-bituminous Pulverised

Wet Bottom

9

0.9

590

1.6

87

1.0

240

1.6

NAV

Circulating Bed

310

1.0

68

96

NAV

Bubbling Bed

NAV

Bituminous Spreader Stokers
Bit./Sub-bit. Fluidised Bed Combustor

310

1.0

270

96

Anthracite Stokers

10

NAV

160

NAV

NAV

Anthr. Fluidised Bed Combustor Boilers

5.2

NAV

31

NAV

NAV

Anthracite Pulverised Coal Boilers

NAV

NAV

310

NAV

NAV

15

3.0

170

0.3

NAV

Oil
Residual Fuel Oil Boilers
Distillate Fuel Oil Boilers

16

0.2

65

0.4

NAV

Small Waste Oil Boilers <0.1MW

15

NAV

58

NAV

NAV

17

NAV

96

NAV

NAV

Butane

16

NAV

97

NAV

NAV

Gasoline <250hp (186 kW)

27

NAV

0.7

NAV

NAV

Diesel <600hp (447 kW)

0.4

NAV

1.9

NAV

NAV

0.3

0.0

1.3

NAV

NAV

Large Boilers >100 MBtu/h (293 MW)

18

1.4

250

NAV

NAV

Small Boilers 10-100 MBtu/h (29.3-293 MW)

16

1.4

64

NAV

NAV

Turbines

2.0

0.6

4.1

NAV

NAV

2-Cycle Lean Burn

4.7

17

33

NAV

NAV

4-Cycle Lean Burn

5.1

13

39

NAV

NAV

4-Cycle Rich Burn

20

2.9

28

NAV

NAV

Fuel Cell/Dutch Oven Boilers

290

NAV

17

NAV

NAV

Stoker Boilers

590

15

65

NAV

NAV

FBC Boilers

61

NAV

87

NAV

NAV

Bagasse/Ag. Waste Boilers

NAV

NAV

68

NAV

NAV

Mass Burn Waterwall

22

NAV

170

NAV

NAV

Mass Burn Rotary Waterwall

36

NAV

110

NAV

NAV

Mass Burn Rotary Refrac. Wall

64

NAV

120

NAV

NAV

Modular, Excess Air

NAV

NAV

120

NAV

NAV

Modular, Starved Air

14

NAV

150

NAV

NAV

90

NAV

240

NAV

NAV

LPG Boilers

PropaneSmall Stationary Internal Comb. Engines
Large Stationary Diesel Engines >600hp (447 kW)
Natural Gas

Heavy Duty Nat. Gas Compressor Eng.

Wood

MSW
MSW Boilers

Refuse Derived Combustors
Source: US EPA (1995).

1.54

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual

1

ENERGYTABLE 1-17
KILNS, OVENS, AND DRYERS SOURCE PERFORMANCE
Emission Factors (kg/TJ energy input)(a)Industry

Source

CO

CH4

NOx

N 2O

NMVOCsCement, Lime

Kilns - Natural Gas

83

1.1

1,111

NAV

NAV

Cement, Lime

Kilns - Oil

79

1.0

527

NAV

NAV

Cement, Lime

Kilns - Coal

79

1.0

527

NAV

NAV

Coking, Steel

Coke Oven

211

1

35(b)

NAV

16(b)

Chemical Processes, Wood, Asphalt,
Copper, Phosphate

Dryer - Natural Gas

11

1.1

64

NAV

NAV

Chemical Processes, Wood, Asphalt,
Copper, Phosphate

Dryer - Oil

16

1.0

168

NAV

NAV

Chemical Processes, Wood, Asphalt,
Copper, Phosphate

Dryer - Coal

179

1.0

226

NAV

NAV

Source: Radian, 1990.
(a) Values were originally based on gross calorific value; they were converted to net calorific value by assuming that net calorificvalues were 5 per cent lower than gross calorific values for coal and oil, and 10 per cent lower for natural gas. These
percentage adjustments are the OECD/IEA assumption on how to convert from gross to net calorific values.
(b) Joint EMEP/CORINAIR (1996).

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual

1.55

ENERGY

TABLE 1-18
RESIDENTIAL SOURCE PERFORMANCE
Emission Factors (kg/TJ energy input)
Basic Technology

Configuration

CO

CH4

NOx

N 2O

NMVOCsCoal
Anthracite Space Heaters
Coal Hot Water Heaters(a)

NAV

150

55

NAV

NAV

18

NAV

160

NAV

NAV

Coal Furnaces(a)

480

NAV

230

NAV

NAV

Coal Stoves(a)

3600

NAV

180

NAV

NAV

Residual Fuel Oil

15

1.4

170

NAV

NAV

Distillate Fuel Oil

16

0.7

65

NAV

NAV

Furnaces

16

5.8

59

0.2

NAV

Propane/Butane Furnaces(a)

10

1.1

47

NAV

NAV

Furnaces

18

NAV

43

NAV

NAV

Gas Heaters(a)

10

1

47

NAV

NAV

Oil

Natural Gas

Wood
Wood Pits(a)

4900

200

150

NAV

NAV

Fireplaces

11000

NAV

110

NAV

NAV

Conventional

10000

210

120

NAV

NAV

Non-catalytic

6100

NAV

NAV

NAV

NAV

Catalytic

4500

380

87

NAV

NAV

Pellet, Certified

1700

NAV

600

NAV

NAV

Pellet, Exempt

2300

NAV

NAV

NAV

NAV

Exempt

6500

NAV

NAV

NAV

NAV

StovesMasonry Heater
Source: US EPA (1995).
(a) Adapted from Radian, 1990.

1.56

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual

1

ENERGYTABLE 1-19
COMMERCIAL SOURCE PERFORMANCE
Emission Factors (kg/TJ energy input)
Basic Technology

Configuration

CO

CH4

NOx

N 2O

NMVOCs

200

10

240

NAV

NAV

Coal
Coal Boilers(a)OilResidual Fuel Oil/Shale Oil

15

1.4

170

0.3

NAV

Distillate Fuel Oil

16

0.7

65

0.4

NAV

5.0

NAV

33

NAV

NAV

Waste Oil Space Heaters
LPG Boilers

Vaporising Burner
Atomising Burner

6.3

NAV

48

NAV

NAV

Propane

8.4

NAV

71

NAV

NAV

Butane

12

NAV

70

NAV

NAV

9.4

1.2

45

2.3

NAV

440

NAV

130

NAV

NAV

Natural Gas
Boilers
Wood
Incineration - high efficiency(a)Waste
Mass Burn Waterwall

22

NAV

170

NAV

NAV

Combustors

NAV

NAV

NAV

NAV

NAV

MSW Boilers(a)

19

NAV

460

NAV

NAV

Source: US EPA (1995).
(a) Adapted from Radian, 1990.

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual

1.57

ENERGY

TABLE 1-20
UTILITY EMISSION CONTROLS PERFORMANCE
Technology

Efficiency
Loss(a)
(%)

Date
CH4
NOx
N 2O
NMVOCsCO
Reduction Reduction Reduction Reduction Reduction Available(b)
(%)

(%)

(%)

(%)

(%)

Low Excess Air (LEA)

-0.5

+

+

15

NAV

NAV

1970

Overfire Air (OFA) - Coal

0.5

+

+

25

NAV

NAV

1970

OFA - Gas

1.25

+

+

40

NAV

NAV

1970

OFA - Oil

0.5

+

+

30

NAV

NAV

1970

Low NOx Burner (LNB) - Coal

0.25

+

+

35

NAV

NAV

1980

LNB - Tangentially Fired

0.25

+

+

35

NAV

NAV

1980

LNB - Oil

0.25

+

+

35

NAV

NAV

1980

LNB - Gas

0.25

+

+

50

NAV

NAV

1980

Cyclone Combustion Modification

0.5

NAV

NAV

40

NAV

NAV

1990

Ammonia Injection

0.5

+

+

60

NAV

NAV

1985

Selective Catalytic Reduction (SCR)- Coal

1

8

+

80

NAV

NAV

1985

SCR - Oil, AFBC

1

8

+

80

NAV

NAV

1985

SCR - Gas

1

8

+

80

60

NAV

1985

Water Injection - Gas Turbine
Simple Cycle

1

+

+

70

NAV

NAV

1975

SCR - Gas Turbine

1

8

+

80

60

NAV

1985

Retrofit LEA

-0.5

+

+

15

NAV

NAV

1970

Retrofit OFA - Coal

0.5

+

+

25

NAV

NAV

1970

Retrofit OFA - Gas

1.25

+

+

40

NAV

NAV

1970

Retrofit OFA - Oil

0.5

+

+

30

NAV

NAV

1970

Retrofit LNB - Coal

0.25

+

+

35

NAV

NAV

1980

Retrofit LNB - Oil

0.25

+

+

35

NAV

NAV

1980

Retrofit LNB - Gas

0.25

+

+

50

NAV

NAV

1980

Burners Out of Service

0.5

+

+

30

NAV

NAV

1975

(a) Efficiency loss as a percentage of end-user energy conversion efficiency (ratio of energy output to energy input for eachtechnology) due to the addition of an emission control technology. Negative loss indicates an efficiency improvement.
(b) Date technology is assumed to be commercially available.
Note: A "+" indicates negligible reduction.
Source: Radian, 1990.

1.58

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual

1

ENERGYTABLE 1-21
INDUSTRIAL BOILER EMISSION CONTROLS PERFORMANCE
Technology

CH4
NOx
N 2O
NMVOCs
Date
Efficiency
CO
Loss(a) Reduction Reduction Reduction Reduction Reduction Available(b)
(%)

(%)

(%)

(%)

(%)

(%)

Low Excess Air (LEA)

-0.5

+

+

15

NAV

NAV

1970

Overfire Air (OFA) - Coal

0.5

+

+

25

NAV

NAV

1970

OFA - Gas

1.25

+

+

40

NAV

NAV

1970

OFA - Oil

0.5

+

+

30

NAV

NAV

1970

Low NOx Burner (LNB) - Coal

0.25

+

+

35

NAV

NAV

1980

LNB - Oil

0.25

+

+

35

NAV

NAV

1980

LNB - Gas

0.25

+

+

50

NAV

NAV

1980

Flue Gas Recirculation

0.5

+

+

40

NAV

NAV

1975

Ammonia Injection

0.5

+

+

60

NAV

NAV

1985

Selective Catalytic Reduction(SCR) - Coal

1

8

+

80

NAV

NAV

1985

SCR - Oil, AFBC

1

8

+

80

NAV

NAV

1985

SCR - Gas

1

8

+

80

60

NAV

1985

Retrofit LEA

-0.5

+

+

15

NAV

NAV

1970

Retrofit OFA - Coal

0.5

+

+

25

NAV

NAV

1970

Retrofit OFA - Gas

1.25

+

+

40

NAV

NAV

1970

Retrofit OFA - Oil

0.5

+

+

30

NAV

NAV

1970

Retrofit LNB - Coal

0.25

+

+

35

NAV

NAV

1980

Retrofit LNB - Oil

0.25

+

+

35

NAV

NAV

1980

Retrofit LNB - Gas

0.25

+

+

50

NAV

NAV

1980

(a) Efficiency loss as a percentage of end-user energy conversion efficiency (ratio of energy output to energy input for eachtechnology) due to the addition of an emission control technology. Negative loss indicates an efficiency improvement.
(b) Date technology is assumed to be commercially available.
Note: A "+" indicates negligible reduction.
Source: Radian, 1990.

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual

1.59

ENERGY

TABLE 1-22
KILN, OVENS, AND DRYERS EMISSION CONTROLS PERFORMANCE

Technology

CH4
NOx
N 2O
CO
NMVOCs
Date
Efficiency
Loss(a) Reduction Reduction Reduction Reduction Reduction Available(b)
(%)

(%)

(%)

(%)

(%)

(%)

LEA - Kilns, Dryers

-6.4

+

+

14

NAV

NAV

1980

LNB - Kilns, Dryers

0

+

+

35

NAV

NAV

1985

SCR - Coke Oven

1.0

8

+

80

60

NAV

1979

Nitrogen Injection

NAV

NAV

NAV

30

NAV

NAV

1990

Fuel Staging

NAV

NAV

NAV

50

NAV

NAV

1995

(a) Efficiency loss as a percentage of end-user energy conversion efficiency (ratio of energy output to energy input for eachtechnology) due to the addition of an emission control technology. Negative loss indicates an efficiency improvement.
(b) Date technology is assumed to be commercially available.
Note: A "+" indicates negligible reduction.
Source: Radian, 1990.

1.60

Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories:

Reference Manual