Chapter 2: Stationary Combustion

CHAPTER 2

STATIONARY COMBUSTION

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.1

Volume 2: Energy

Authors
Darío R. Gómez (Argentina) and John D. Watterson (UK)
Branca B. Americano (Brazil), Chia Ha (Canada), Gregg Marland (USA), Emmanuel Matsika (Zambia), Lemmy
Nenge Namayanga (Zambia), Balgis Osman-Elasha (Sudan), John D. Kalenga Saka (Malawi), and Karen
Treanton (IEA)

Contributing Author
Roberta Quadrelli (IEA)

2.2

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

Contents2

Stationary Combustion
2.1

Overview ...............................................................................................................................................2.6

2.2

Description of sources...........................................................................................................................2.6

2.3

Methodological issues .........................................................................................................................2.11

2.3.1

Choice of method ........................................................................................................................2.11

2.3.1.1

Tier 1 approach ......................................................................................................................2.11

2.3.1.2

Tier 2 approach ......................................................................................................................2.12

2.3.1.3

Tier 3 approach ......................................................................................................................2.12

2.3.1.4

Decision trees.........................................................................................................................2.14

2.3.2 Choice of emission factors ..................................................................................................................2.14
2.3.2.1

Tier 1......................................................................................................................................2.14

2.3.2.2

Tier 2 country-specific emission factors................................................................................2.24

2.3.2.3

Tier 3 technology-specific emission factors ..........................................................................2.24

2.3.3

Choice of activity data.................................................................................................................2.24

2.3.3.1

Tier 1 and tier 2......................................................................................................................2.29

2.3.3.2

Tier 3......................................................................................................................................2.32

2.3.3.3

Avoiding double counting activity data with other sectors....................................................2.32

2.3.3.4

Treatment of biomass.............................................................................................................2.33

2.3.4

Carbon dioxide capture ...............................................................................................................2.34

2.3.5

Completeness ..............................................................................................................................2.37

2.3.6

Developing a consistent time series and recalculation ................................................................2.37

2.4

Uncertainty assessment .......................................................................................................................2.38

2.4.1

Emission factor uncertainties ......................................................................................................2.38

2.4.2

Activity data uncertainties...........................................................................................................2.40

2.5

Inventory Quality Assurance/Quality Control QA/QC .......................................................................2.41

2.5.1
2.6

Reporting and Documentation.....................................................................................................2.41

Worksheets..........................................................................................................................................2.42

References.....................................................................................................................................................2.45

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.3

Volume 2: Energy

Equations
Equation 2.1

Greenhouse gas emissions from stationary combustion ......................................................2.11

Equation 2.2

Total emissions by greenhouse gas......................................................................................2.12

Equation 2.3

Greenhouse gas emissions by technology ...........................................................................2.12

Equation 2.4

Fuel consumption estimates based on technology penetration ............................................2.13

Equation 2.5

Technology-based emission estimation ...............................................................................2.13

Equation 2.6

CO2 capture efficiency.........................................................................................................2.35

Equation 2.7

Treatment of CO2 capture....................................................................................................2.36

FiguresFigure 2.1

Generalised decision tree for estimating emissions from stationary combustion ................2.15

Figure 2.2

Power and heat plants use fuels to produce electric power and/or useful heat. ...................2.30

Figure 2.3

A refinery uses energy to transform crude oil into petroleum products. .............................2.31

Figure 2.4

Fuels are used as an energy source in manufacturing industries to convert raw
materials into products.........................................................................................................2.31

Figure 2.5

CO2 capture systems from stationary combustion sources ..................................................2.34

Figure 2.6

Carbon flows in and out of the system boundary for a CO2 capture systemassociated with stationary combustion processes ................................................................2.35

Tables

2.4

Table 2.1

Detailed sector split for stationary combustion .....................................................................2.7

Table 2.2

Default emission factors for stationary combustion in the energy industries(kg of greenhouse gas per TJ on a net calorific basis).........................................................2.16

Table 2.3

Default emission factors for stationary combustion in manufacturing industries andconstruction (kg of greenhouse gas per TJ on a net calorific basis) ...................................2.18

Table 2.4

Default emission factors for stationary combustion in the commercial/institutional category(kg of greenhouse gas per TJ on a net calorific basis) ........................................................2.20

Table 2.5

Default emission factors for stationary combustion in theresidential and agriculture/forestry/fishing/fishing farms categories(kg of greenhouse gas per TJ on a net calorific basis) ........................................................2.22

Table 2.6

Utility source emission factors ............................................................................................2.25

Table 2.7

Industrial source emission factors .......................................................................................2.26

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

Table 2.8

Kilns, ovens, and dryers source emission factors ................................................................2.27

Table 2.9

Residential source emission factors.....................................................................................2.28

Table 2.10

Commercial/institutional source emission factors ...............................................................2.29

Table 2.11

Typical CO2 capture efficiencies for post and pre-combustion systems..............................2.36

Table 2.12

Default uncertainty estimates for stationary combustion emission factors..........................2.38

Table 2.13

Summary of uncertainty assessment of CO2 emission factors for stationary combustion
sources of selected countries ...............................................................................................2.39

Table 2.14

Summary of uncertainty assessment of CH4 and N2O emission factors for stationary
combustion sources of selected countries............................................................................2.40

Table 2.15

Level of uncertainty associated with stationary combustion activity data...........................2.41

Table 2.16

List of source categories for stationary combustion ............................................................2.42

Table 2.17

QA/QC procedures for stationary sources ...........................................................................2.43

Box
Box 2.1

Autoproducers .....................................................................................................................2.11

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.5

Volume 2: Energy

2 STATIONARY COMBUSTION
2.1

OVERVIEWThis chapter describes the methods and data necessary to estimate emissions from Stationary Combustion, andthe categories in which these emissions should be reported. Methods are provided for the sectoral approach inthree tiers based on:•

Tier 1: fuel combustion from national energy statistics and default emission factors;•

Tier 2: fuel combustion from national energy statistics, together with country-specific emission factors,
where possible, derived from national fuel characteristics;•

Tier 3: fuel statistics and data on combustion technologies applied together with technology-specificemission factors; this includes the use of models and facility level emission data where available.

The chapter provides default Tier 1 emission factors for all source categories and fuels. The IPCC Emission
Factor Database1 may be consulted for information appropriate to national circumstances, though the correct useof information from the database is the responsibility of greenhouse gas inventory compilers.
This chapter covers elements formerly presented in the ‘Energy’ chapter of the GPG2000. The organisation of
the IPCC 2006 Guidelines is different from both the IPCC 1996 Guidelines and the GPG2000. The changes tothe stationary combustion information are summarised below.
Content:•

A table detailing which sectors this chapter covers, and which IPCC source codes the emissions are to bereported under is included.

•

Some of the emission factors have been revised, and some new factors have also been included. The tables
containing the emission factors indicate which factors are new, and which have been revised from the IPCC
1996 Guidelines and GPG2000.

•

The default oxidation factor is assumed to be 1, unless better information is available.

•

In the Tier 1 sectoral approach, the oxidation factor is included with the emission factor, which simplifies
the worksheet.

•

Building on the GPG2000, this chapter includes extended information about uncertainty assessment of boththe activity data and the emission factors.

•

Some definitions have changed or been refined.

•

A new section on carbon dioxide capture and storage has been added.

Structure:•

The methodology for estimating emissions is now subdivided into smaller sections for each Tier approach.

•The tables have been designed to present emission factors for CO2, CH4, and N2O together, where possible.

2.2

DESCRIPTION OF SOURCES

In the Sectoral Approach, emissions from stationary combustion are specified for a number of societal andeconomic activities, defined within the IPCC sector 1A, Fuel Combustion Activities (see Table 2.1). A
distinction is made between stationary combustion in energy industries (1.A.1), manufacturing industries andconstruction (1.A.2) and other sectors (1.A.4). Although these distinct subsectors are intended to include all
stationary combustion, an additional category is available in sector 1.A.5 for any emissions that cannot beallocated to one of the other subcategories. Table 2.1 also indicates the mobile source categories in 1.A.4 and1.A.5 that are treated in Chapter 3 of this Volume.

1

Available at http://www.ipcc-nggip.iges.or.jp/efdb/main.php

2.62006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.1
DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION2
Code number and name

1 ENERGY

All GHG emissions arising from combustion and fugitive
releases of fuels. Emissions from the non-energy uses of fuels
are generally not included here, but reported under Industrial
Processes and Product Use.

1 A Fuel Combustion Activities

Emissions from the intentional oxidation of materials within
an apparatus that is designed to raise heat and provide it either
as heat or as mechanical work to a process or for use awayfrom the apparatus.

1A1

Comprises emissions from fuels combusted by the fuelextraction or energy-producing industries.

Energy Industries

Sum of emissions from main activity producers of electricity
generation, combined heat and power generation, and heatplants. Main activity producers (formerly known as public
utilities) are defined as those undertakings whose primaryactivity is to supply the public. They may be in public or
private ownership. Emissions from own on-site use of fuelshould be included.
Emissions from autoproducers (undertakings which generate
electricity/heat wholly or partly for their own use, as anactivity that supports their primary activity) should be
assigned to the sector where they were generated and notunder 1 A 1 a. Autoproducers may be in public or private
ownership.

1A1aMain Activity
Electricity and Heat
Production

1A1

a

i

Electricity
Generation

Comprises emissions from all fuel use for electricity
generation from main activity producers except those fromcombined heat and power plants.

ii

Combined
Heat andPower
Generation(CHP)

Emissions from production of both heat and electrical powerfrom main activity producers for sale to the public, at a single
CHP facility.

iii

Heat Plants

Production of heat from main activity producers for sale bypipe network.

1A1

1A1

2

Definitionsab

Petroleum Refining

All combustion activities supporting the refining of petroleum
products including on-site combustion for the generation ofelectricity and heat for own use. Does not include evaporativeemissions occurring at the refinery. These emissions should bereported separately under 1 B 2 a.

Methods for mobile sources occurring in sub-categories 1 A 4 and 1 A 5 are dealt with in Chapter 3 and the emissions arereported under Stationary Combustion.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.7

Volume 2: Energy

TABLE 2.1 (CONTINUED)
DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION3
Code number and name

1A1c

Manufacture of Solid
Fuels and Other Energy
Industries

Combustion emissions from fuel use during the manufactureof secondary and tertiary products from solid fuels including
production of charcoal. Emissions from own on-site fuel use
should be included. Also includes combustion for thegeneration of electricity and heat for own use in theseindustries.

1A1

c

i

Manufacture ofSolid Fuels

Emissions arising from fuel combustion for the production ofcoke, brown coal briquettes and patent fuel.

Other Energy
Industries

Combustion emissions arising from the energy-producing
industries own (on-site) energy use not mentioned above orfor which separate data are not available. This includes theemissions from own-energy use for the production of
charcoal, bagasse, saw dust, cotton stalks and carbonizing of
biofuels as well as fuel used for coal mining, oil and gas
extraction and the processing and upgrading of natural gas.
This category also includes emissions from pre-combustion
processing for CO2 capture and storage. Combustion
emissions from pipeline transport should be reported under1 A 3 e.

1A1

3

Definitions

c

ii

1A2

Manufacturing Industries
and Construction

Emissions from combustion of fuels in industry. Also includes
combustion for the generation of electricity and heat for own
use in these industries. Emissions from fuel combustion incoke ovens within the iron and steel industry should bereported under 1 A 1 c and not within manufacturing industry.
Emissions from the industry sector should be specified bysub-categories that correspond to the International Standard
Industrial Classification of all Economic Activities (ISIC).
Energy used for transport by industry should not be reported
here but under Transport (1 A 3). Emissions arising from offroad and other mobile machinery in industry should, if
possible, be broken out as a separate subcategory. For eachcountry, the emissions from the largest fuel-consuming
industrial categories ISIC should be reported, as well as thosefrom significant emitters of pollutants. A suggested list of
categories is outlined below.

1A2

a

Iron and Steel

ISIC Group 271 and Class 2731

1A2b

Non-Ferrous Metals

ISIC Group 272 and Class 2732

1A2

c

Chemicals

ISIC Division 24

1A2

d

Pulp, Paper and Print

ISIC Divisions 21 and 22

1A2

e

Food Processing,Beverages andTobaccoISIC Divisions 15 and 16

1A2

f

Non-Metallic
Minerals

Includes products such as glass, ceramic, cement, etc.; ISIC
Division 26

1A2

g

Transport Equipment

ISIC Divisions 34 and 35

1A2

hMachinery

Includes fabricated metal products, machinery and equipment
other than transport equipment; ISIC Divisions 28, 29, 30, 31
and 32.

Methods for mobile sources occurring in sub-categories 1 A 4 and 1 A 5 are dealt with in Chapter 3 and the emissions arereported under Stationary Combustion.

2.8

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.1 (CONTINUED)
DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION4
Code number and name4

Definitions

1A2

i

Mining (excluding
fuels) and Quarrying

ISIC Divisions 13 and 14

1A2

jWood and Wood
Products

ISIC Division 20

1A2

kConstruction

ISIC Division 45

1A2l

Textile and Leather

ISIC Divisions 17, 18 and 19

1A2

m

Non-specified
Industry

Any manufacturing industry/construction not included aboveor for which separate data are not available. Includes ISIC
Divisions 25, 33, 36 and 37.

1A4

Other Sectors

1A4aCommercial /Institutional

Emissions from fuel combustion in commercial andinstitutional buildings; all activities included in ISIC Divisions
41, 50, 51, 52, 55, 63-67, 70-75, 80, 85, 90-93 and 99.

1A4bResidential

All emissions from fuel combustion in households.

1A4c

Agriculture / Forestry/ Fishing / Fish farms

Emissions from fuel combustion in agriculture, forestry,
fishing and fishing industries such as fish farms. Activities
included in ISIC Divisions 01, 02 and 05. Highway
agricultural transportation is excluded.

1A4

c

i

Stationary

Emissions from fuels combusted in pumps, grain drying,horticultural greenhouses and other agriculture, forestry or
stationary combustion in the fishing industry.
Emissions from fuels combusted in traction vehicles on farmland and in forests.
Emissions from fuels combusted for inland, coastal and deepsea fishing. Fishing should cover vessels of all flags that haverefuelled in the country (include international fishing).

Emissions from combustion activities as described below,
including combustion for the generation of electricity and heatfor own use in these sectors.

1A4

c

ii

Off-road
Vehicles andOther
Machinery

1A4

c

iii

Fishing(mobilecombustion)

Methods for mobile sources occurring in sub-categories 1 A 4 and 1 A 5 are dealt with in Chapter 3 and the emissions arereported under Stationary Combustion.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.9

Volume 2: Energy

TABLE 2.1 (CONTINUED)
DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION5
Code number and nameDefinitions

1A5

Non-Specified

All remaining emissions from fuel combustion that are notspecified elsewhere. Include emissions from fuel delivered tothe military in the country and delivered to the military ofother countries that are not engaged in multilateral operations.

1A5

aStationary

Emissions from fuel combustion in stationary sources that are
not specified elsewhere.

1A5bMobileEmissions from vehicles and other machinery, marine andaviation (not included in 1 A 4 c ii or elsewhere).

1A5

b

i

Mobile(aviation
component)

All remaining aviation emissions from fuel combustion thatare not specified elsewhere. Include emissions from fueldelivered to the country’s military as well as fuel delivered
within that country but used by the militaries of othercountries that are not engaged in multilateral operations.
All remaining water-borne emissions from fuel combustionthat are not specified elsewhere. Include emissions from fueldelivered to the country’s military as well as fuel delivered
within that country but used by the militaries of othercountries that are not engaged in multilateral operations.
All remaining emissions from mobile sources not included
elsewhere.

1A5

b

ii

Mobile (waterborne
component)

1A5

b

iii

Mobile (other)

Multilateral operations(Information item)

Emissions from fuels used in multilateral operations pursuant
to the Charter of the United Nations. Include emissions fromfuel delivered to the military in the country and delivered tothe military of other countries.

The category “Manufacturing industries and Construction” has been subdivided using the International Standard
Industrial Classification6. This industrial classification is widely used in energy statistics. Note that this tableadds a number of industrial sectors in the category “Manufacturing Industries and Construction” to better alignto the ISIC definitions and common practice in energy statistics.
Emissions from autoproducers (public or private undertakings that generate electricity/heat wholly or partly for
their own use, as an activity that supports their primary activity, see Box 2.1) should be assigned to the sector
where they were generated and not under 1 A 1 a.

5

6

Methods for mobile sources occurring in sub-categories 1 A 4 and 1 A 5 are dealt with in Chapter 3 and the emissions arereported under Stationary Combustion.
International Standard Industrial Classification of all Economic Activities, United Nations, New York. The publication canbe downloaded from http://unstats.un.org/unsd/cr/.

2.10

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

BOX 2.1
AUTOPRODUCERS

An autoproducer of electricity and/or heat is an enterprise that, in support of its primary activity,
generates electricity and/or heat for its own use or for sale, but not as its main business. Thisshould be contrasted with main activity producers who generate and sell electricity and/or heat astheir primary activity. Main activity producers were previously referred to as “Public” electricity
and heat suppliers, although, as with autoproducers, they might be publicly or privately owned.
Note that the ownership does not determine the allocation of emissions.
The IPCC 2006 Guidelines follow the IPCC 1996 Guidelines in attributing emissions from
autoproduction to the industrial or commercial branches in which the generation activity occurred,rather than to 1 A 1 a. Category 1 A 1a is for main activity producers only.
With the complexity of plant activities and inter-relationships, there may not always be a clear
separation between autoproducers and main activity producers. The most important issue is that all
facilities be accounted under the most appropriate category and in a complete and consistentmanner.

2.3

METHODOLOGICAL ISSUESThis section explains how to choose an approach, and summarises the necessary activity data and emission
factors the inventory compiler will need. These sections are subdivided into Tiers as set out in Volume 1 General
Guidance. The Tier 1 sections set out the steps needed for the simplest calculation methods, or the methods that
require the least data. These are likely to provide the least accurate estimates of emissions. The Tier 2 and Tier 3
approaches require more detailed data and resources (time, expertise and country-specific data) to produce anestimate of emissions. Properly applied, the higher tiers should be more accurate.

2.3.1

Choice of method

In general, emissions of each greenhouse gas from stationary sources are calculated by multiplying fuelconsumption by the corresponding emission factor. In the Sectoral Approach, “Fuel Consumption” is estimatedfrom energy use statistics and is measured in terajoules. Fuel consumption data in mass or volume units mustfirst be converted into the energy content of these fuels. All tiers described below use the amount of fuelcombusted as the activity data. Section 1.4.1.2 of the Introduction chapter contains information on how to findand apply energy statistics data. Different tiers can be applied for different fuels and gases, consistent with therequirements of key category analysis and avoidance of double counting (see also the General Decision Tree insection 1.3.1.2).

2.3.1.1

T IER 1 APPROACH

Applying a Tier 1 emission estimate requires the following for each source category and fuel:•Data on the amount of fuel combusted in the source category•

A default emission factor

Emission factors come from the default values provided together with associated uncertainty range in Section
2.3.2.1. The following equation is used:
EQUATION 2.1
GREENHOUSE GAS EMISSIONS FROM STATIONARY COMBUSTION
EmissionsGHG, fuel = Fuel Consumption fuel • Emission FactorGHG, fuelWhere:
EmissionsGHG ,fuel= emissions of a given GHG by type of fuel (kg GHG)

Fuel Consumptionfuel= amount of fuel combusted (TJ)

Emission FactorGHG,fuel= default emission factor of a given GHG by type of fuel (kg gas/TJ). For
CO2, it includes the carbon oxidation factor, assumed to be 1.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.11

Volume 2: Energy

To calculate the total emissions by gas from the source category, the emissions as calculated in Equation 2.1 aresummed over all fuels:
EQUATION 2.2
TOTAL EMISSIONS BY GREENHOUSE GASEmissions GHG = ∑ Emissions GHG , fuelfuels

2.3.1.2

T IER 2 APPROACH

Applying a Tier 2 approach requires:•

Data on the amount of fuel combusted in the source category;•A country-specific emission factor for the source category and fuel for each gas.

Under Tier 2, the Tier 1 default emission factors in Equation 2.1 are replaced by country-specific emission
factors. Country-specific emission factors can be developed by taking into account country-specific data, forexample carbon contents of the fuels used, carbon oxidation factors, fuel quality and (for non-CO2 gases inparticular) the state of technological development. The emission factors may vary over time and, for solid fuels,
should take into account the amount of carbon retained in the ash, which may also vary with time. It is goodpractice to compare any country-specific emission factor with the default ones given in Tables 2.2 to 2.5. If suchcountry-specific emission factors are outside the 95 percent confidence intervals, given for the default values, anexplanation should be sought and provided on why the value is significantly different from the default value.
A country-specific emission factor can be identical to the default one, or it may differ. Since the country-specificvalue should be more applicable to a given country’s situation, it is expected that the uncertainty range
associated with a country-specific value will be smaller than the uncertainty range of the default emission factor.
This expectation should mean that a Tier 2 estimate provides an emission estimate with lower uncertainty than a
Tier 1 estimate.
Emissions can be also estimated as the product of fuel consumption on a mass or volume basis, and an emission
factor expressed on a compatible basis. For example, the use of activity data expressed in mass unit is relevant
when the Tier 2 approach described in Chapter 5 of Volume 5 is used alternatively to estimate emissions thatarise when waste is incinerated for energy purposes.

2.3.1.3

T IER 3 APPROACH

The Tier 1 and Tier 2 approaches of estimating emissions described in the previous sections necessitate using an
average emission factor for a source category and fuel combination throughout the source category. In reality,
emissions depend on the:•fuel type used,•

combustion technology,•

operating conditions,•control technology,•

quality of maintenance,•

age of the equipment used to burn the fuel.

In a Tier 3 approach this is taken into account by splitting the fuel combustion statistics over the different
possibilities and using emission factors that are dependent upon these differences. In Equation 2.3, this isindicated by making the variables and parameters technology dependent. Technology here stands for any device,
combustion process or fuel property that might influence the emissions.
EQUATION 2.3
GREENHOUSE GAS EMISSIONS BY TECHNOLOGY
EmissionsGHG, fuel ,technology = Fuel Consumption fuel,technology • Emission FactorGHG, fuel,technology
Where:

2.12

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

EmissionsGHG gas,fuel, technology
GHG)= emissions of a given GHG by type of fuel and technology (kgFuel Consumptionfuel, technology= amount7 of fuel combusted per type of technology (TJ)

Emission FactorGHG gas,fuel,technology= emission factor of a given GHG by fuel and technology type
(kg GHG/TJ)

When the amount of fuel combusted for a certain technology is not directly known, it can be estimated by meansof models. For example, a simple model for this is based on the penetration of the technology into the source
category.
EQUATION 2.4
FUEL CONSUMPTION ESTIMATES BASED ON TECHNOLOGY PENETRATION
Fuel Consumption fuel ,technology = Fuel Consumption fuel • Penetrationtechnology
Where:
Penetrationtechnology =the fraction of the full source category occupied by a given technology. This
fraction can be determined on the basis of output data such as electricity
generated which would ensure that appropriate allowance was made fordifferences in utilisation between technologies.

To calculate the emissions of a gas for a source category, the result of Equation 2.3 must be summed over alltechnologies applied in the source category.
EQUATION 2.5
TECHNOLOGY-BASED EMISSION ESTIMATION
Emissions GHG , fuel =∑ Fuel Consumption fuel ,technology • Emission FactorGHG, fuel ,technology
technologies

Total emissions are again calculated by summing over all fuels (Equation 2.2).
Application of a Tier 3 emission estimation approach requires:•

Data on the amount of fuel combusted in the source category for each relevant technology (fuel type used,
combustion technology, operating conditions, control technology, and maintenance and age of theequipment).

•

A specific emission factor for each technology (fuel type used, combustion technology, operating conditions,control technology, oxidation factor, and maintenance and age of the equipment).

•

Facility level measurements can also be used when available.

Using a Tier 3 approach to estimate emissions of CO2 is often unnecessary because emissions of CO2 do notdepend on the combustion technology. However, plant-specific data on CO2 emissions are increasingly available
and they are of increasing interest because of the possibilities for emissions trading. Plant-specific data can bebased on fuel flow measurements and fuel chemistry or on flue gas flow measurements and flue gas chemistrydata. Continuous emissions monitoring (CEM) of flue gases is generally not justified for accurate measurementof CO2 emissions alone (because of the comparatively high cost) but could be undertaken particularly whenmonitors are installed for measurement of other pollutants such as SO2 or NOx. Continuous emissions
monitoring is also particularly useful for combustion of solid fuels where it is more difficult to measure fuel flow
rates, or when fuels are highly variable, or fuel analysis is otherwise expensive. Rigorous, continuous monitoringis required to provide a comprehensive accounting of emissions. Care is required when continuous emissions
monitoring of some facilities is used but monitoring data are not available for a full reporting category.
Continuous emissions monitoring requires attention to quality assurance and quality control. This includes
certification of the monitoring system, re-certification after any changes in the system, and assurance ofcontinuous operation 8 . For CO2 measurements, data from CEM systems can be compared with emissions
estimates based on fuel flows.
7

Fuel consumption could be expressed on a mass or volume basis, and emissions can be estimated as the product of fuelconsumption and an emission factor expressed on a compatible basis.

8

See for example: U.S. EPA (2005a).

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.13

Volume 2: Energy

If detailed monitoring shows that the concentration of a greenhouse gas in the discharge from a combustion
process is equal to or less than the concentration of the same gas in the ambient intake air to the combustion
process, then emissions may be reported as zero. Reporting these emissions as “negative emissions” would
require continuous high quality monitoring of both the air intake and the atmospheric emissions.

2.3.1.4

D ECISION TREESThe tier used to estimate emissions will depend on the quantity and quality of data that are available. If a
category is key, it is good practice to estimate emissions using a Tier 2 or Tier 3 approach. The decision tree
(Figure 2.1) below will help in selecting which tier should be used to estimate emissions from sources ofstationary combustion.
To use a decision tree correctly, the inventory compiler needs to undertake a thorough survey of available
national activity data and national or regional emission factor data, by relevant source category. This survey
needs to be completed before the first inventory is compiled, and the results of the survey should be reviewed
regularly. It is good practice to improve the data quality if an initial calculation with a Tier 1 approach indicatesa key source, or if an estimate is associated with a high level of uncertainty. The decision tree and key source
category determination should be applied to CO2, CH4 and N2O emissions separately.

2.3.2

Choice of emission factors

This section provides default emission factors for CO2, CH4 and N2O, and discusses provision of emission
factors at higher Tiers. CO2 emission factors for all Tiers reflect the full carbon content of the fuel less any nonoxidised fraction of carbon retained in the ash, particulates or soot. Since this fraction is usually small, the Tier 1
default emission factors derived in Chapter 1 of this Volume neglect this effect by assuming a complete
oxidation of the carbon contained in the fuel (carbon oxidation factor equal to 1). For some solid fuels, thisfraction will not necessarily be negligible, and higher Tier estimates can be applied. Where this is known to be
the case it is good practice to use country-specific values, based on measurements or other well documented data.
The Emission Factor Database (EFDB) provides a variety of well-documented emission factors and otherparameters that may be better suited to national circumstances than the default values, although the responsibility
to ensure appropriate application of material from the database remains with the inventory compiler.

2.3.2.1

T IER 1This section presents for each of the fuels used in stationary sources a set of default emission factors for use inTier 1 emission estimates for the source categories. In a number of source categories, the same fuels are used.
These will have the same emission factors for CO2. The derivation of the CO2 emission factors is presented in the
Introduction chapter of this Volume. Emission factors for CO2 are in units of kg CO2/TJ on a net calorific value
basis and reflect the carbon content of the fuel and the assumption that the carbon oxidation factor is 1.
Emission factors for CH4 and N2O for different source categories differ due to differences in combustion
technologies applied in the different source categories. The default factors presented for Tier 1 apply totechnologies without emission controls. The default emission factors, particularly those in Tables 2.2 and 2.3,
assume effective combustion in high temperature. They are applicable for steady and optimal conditions and do
not take into account the impact of start-ups, shut downs or combustion with partial loads.
Default emission factors for stationary combustion are given in Tables 2.2 to 2.5. The CO2 emission factors are
the same ones as presented in Table 1.4 of the Introduction chapter. The emission factors for CH4 and N2O arebased on the IPCC 1996 Guidelines. These emission factors were established using the expert judgement of alarge group of inventory experts and are still considered valid. Since not many measurements of these types ofemission factors are available, the uncertainty ranges are set at plus or minus a factor of three. Tables 2.2 to 2.5
do not provide default emission factors for CH4 and N2O emissions from combustion by off-road machinery thatare reported in the 1A category. These emission factors are provided in Section 3.3 of this Volume.

2.14

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

Figure 2.1

Generalised decision tree for estimating emissions from stationary
combustion
Start

Are
emissions
measurements
available withsatisfactory
QC?

Are allsingle sources inthe source category
measured?

Yes

Usemeasurements
Tier 3 approach.

Yes

No
Is
specific
fuel use
available for the
category?

Yes

Are
countryspecific EFs
available for theunmeasured part of
the key
category?

No

No

Does
the unmeasured
part belong to a key
category?

Can the fuelconsumption estimatedby the model be reconciled withnational fuel statistics or beverified by independentsources?

Yes

No

No

Yes

Are
country-specific EFs
available?
Yes

No
Is thisa key category?

Yes

Get CountrySpecific Data

No

No

Is a detailed
estimation model
available?

Yes

Use
measurements
Tier 3 approachand combine with
AD and countryspecific EFs
Tier 2 approach.

Yes

Use
measurements
Tier 3 approachand combine with
AD and default
EFs Tier 1
approach.

Use model
Tier 3 approach.

Use countryspecific EFs
and suitable AD
Tier 2 approach.

Get countryspecific data.
No

Use default EFs
and suitable AD
Tier 1 approach.

Note: See Volume 1 Chapter 4, “Methodological Choice and Key Categories” (noting section 4.1.2 on limited resources) for
discussion of key categories and use of decision trees.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.15

Volume 2: Energy

TABLE 2.2
DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN THE ENERGY INDUSTRIES(kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

CH4

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor73 30071 10075 500r

Crude Oil

N2O

Lower

Upper

Default
Emission
Factor

Lower

Upper

3

1

10

0.6

0.2

2

r

77 00069 30085 400

r

3

1

10

0.6

0.2

2

Natural Gas Liquidsr

64 20058 30070 400

r

3

1

10

0.6

0.2

2

Motor Gasoliner

69 30067 50073 000

r

3

1

10

0.6

0.2

2

Aviation Gasoliner

70 00067 50073 000

r

3

1

10

0.6

0.2

2

Gasoline

Orimulsion

Jet Gasoliner

70 00067 50073 000

r

3

1

10

0.6

0.2

2

r

71 50069 70074 400

r

3

1

10

0.6

0.2

2

Other Kerosene

71 90070 80073 700

r

3

1

10

0.6

0.2

2

Shale Oil

73 30067 80079 200

r

3

1

10

0.6

0.2

2

Gas/Diesel Oil

74 10072 60074 800

r

3

1

10

0.6

0.2

2

Residual Fuel Oil

77 40075 50078 800

r

3

1

10

0.6

0.2

2

Jet Kerosene

Liquefied Petroleum Gases

63 10061 60065 600

r

1

0.3

3

0.1

0.03

0.3

Ethane61 60056 50068 600

r

1

0.3

3

0.1

0.03

0.3

Naphtha73 30069 30076 300

r

3

1

10

0.6

0.2

2

Bitumen80 70073 00089 900

r

3

1

10

0.6

0.2

2

Lubricants

73 30071 90075 200

r

3

1

10

0.6

0.2

2

97 50082 900115 000

r

3

1

10

0.6

0.2

2

Refinery Feedstocks

73 30068 90076 600

r

3

1

10

0.6

0.2

2

Refinery Gas

Petroleum Coker

48 20069 000

r

1

0.3

3

0.1

0.03

0.3

73 30072 20074 400

r

3

1

10

0.6

0.2

2

White Spirit and SBP

73 30072 20074 400

r

3

1

10

0.6

0.2

2

Other Petroleum Products

73 30072 20074 400

r

3

1

10

0.6

0.2

2

Anthracite

98 30094 600101 000

1

0.3

3

r

1.5

0.5

5

Coking Coal

94 60087 300101 000

1

0.3

3

r

1. 5

0.5

5

Other Bituminous Coal

94 60089 50099 700

1

0.3

3

r

1. 5

0.5

5

Sub-Bituminous Coal

96 10092 800100 000

1

0.3

3

r

1.5

0.5

5

Lignite

101 000

90 900115 000

1

0.3

3

r

1. 5

0.5

5

Oil Shale and Tar Sands

107 000

90 200125 000

1

0.3

3

r

1. 5

0.5

5

Brown Coal Briquettes

97 50087 300109 000

1

0.3

3

r

1. 5

0.5

5

Patent Fuel

97 50087 300109 000

1

0.3

3

n

1. 5

0.5

5

Coke Oven Coke andLignite Coker 107 000

95 700119 000

1

0.3

3

r

1. 5

0.5

5

Gas Coker 107 000

95 700119 000

r

1

0.3

3

0.03

0.3

n 80 700

68 20095 300

n

1

0.3

3

0.5

5

Gas Works Gas

n 44 400

37 30054 100

n

1

0.3

3

0.1

0.03

0.3

Coke Oven Gas

n 44 400

37 30054 100

r

1

0.3

3

0.1

0.03

0.3

Blast Furnace Gas

n 260 000

219 000

308 000

r

1

0.3

3

0.1

0.03

0.3

Oxygen Steel Furnace Gas

n 182 000

145 000

202 000

r

1

0.3

3

0.1

0.03

0.3

56 10054 30058 300

1

0.3

3

0.1

0.03

0.3

Coke

Other Oiln 57 600

Paraffin Waxes

Derived Gases

Coal Tar

Natural Gas

2.16

n

0.1
r

1. 5

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.2 (CONTINUED)DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN THE ENERGY INDUSTRIES(kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

CH4

N2O

Upper

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

Municipal Wastes (non-biomass
fraction)n

91 70073 300121 000

30

10

100

4

1.5

15

Industrial Wastes

n 143 000

110 000

183 000

30

10

100

4

1.5

15

Waste Oils

n

30

10

100

1

0.3

3

30

10

100

3

1

18

73 30072 20074 400106 000

100 000

108 000

Wood / Wood Wasten 112 000

95 000132 000

Sulphite lyes (Black
Liquor)an 95 300

80 700110 000

Other Primary Solid
Biomassn 100 000

84 700117 000

30

10

100

Charcoaln 112 000

95 000132 000

200

70

600

Biogasoline

n 70 800

59 80084 300r

3

1

Biodiesels

n 70 800

59 80084 300r

3

Other Liquid Biofuels

n 79 600

67 10095 300r

Landfill Gas

n 54 600

46 20066 000Gas
Biomass

Lower

Sludge Gas

n 54 600

46 200

Other Biogasn

54 600

Other nonfossil fuels

Default
Emission
FactorMunicipal Wastes(biomass fraction)n 100 000

LiquidBiofuels

Solid Biofuels

Peat

1.5

15

0.5

5

1.5

15

1

21

4

1.5

15

4

1.5

15

10

0.6

0.2

2

1

10

0.6

0.2

2

3

1

10

0.6

0.2

2

r

1

0.3

3

0.1

0.03

0.3

66 000

r

1

0.3

3

0.1

0.03

0.3

46 20066 000

r

1

0.3

3

0.1

0.03

0.3

84 700117 000

30

10

100

4

1.5

15

n

n

4
n

1.5
4

n

2

(a) Includes the biomass-derived CO2 emitted from the black liquor combustion unit and the biomass-derived CO2 emitted from the kraft mill lime kiln.
nindicates a new emission factor which was not present in the 1996 Guidelinesr
indicates an emission factor that has been revised since the 1996 Guidelines

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.17

Volume 2: Energy

TABLE 2.3
DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN MANUFACTURING INDUSTRIES AND CONSTRUCTION(kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

CH4

Lower

Upper

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

Crude Oil

73 30071 10075 500

r

3

1

10

0.6

0.2

2

Orimulsion

r 77 000

69 30085 400

r

3

1

10

0.6

0.2

2

Natural Gas Liquids

r 64 200

58 30070 400

r

3

1

10

0.6

0.2

2

Motor Gasoliner 69 300

67 50073 000

r

3

1

10

0.6

0.2

2

Aviation Gasoline

r 70 000

Jet Gasoline

r 70 000

67 50073 000

r

3

1

10

0.6

0.2

2

67 50073 000

r

3

1

10

0.6

0.2

2

Jet Kerosene

71 50069 70074 400

r

3

1

10

0.6

0.2

2

Other Kerosene

71 90070 80073 700

r

3

1

10

0.6

0.2

2

Shale Oil

73 30067 80079 200

r

3

1

10

0.6

0.2

2

Gas/Diesel Oil

74 10072 60074 800

r

3

1

10

0.6

0.2

2

Gasoline

Default
Emission
FactorN2O

Residual Fuel Oil

77 40075 50078 800

r

3

1

10

0.6

0.2

2

Liquefied Petroleum Gases

63 10061 60065 600

r

1

0.3

3

0.1

0.03

0.3

Ethane61 60056 50068 600

r

1

0.3

3

0.1

0.03

0.3

Naphtha73 30069 30076 300

r

3

1

10

0.6

0.2

2

Bitumen80 70073 00089 900

r

3

1

10

0.6

0.2

2

Lubricants

73 30071 90075 200

r

3

1

10

0.6

0.2

2

r 97 500

82 900115 000

r

3

1

10

0.6

0.2

2

Petroleum Coke

73 30068 90076 600

r

3

1

10

0.6

0.2

2

Refinery Gas

n 57 600

48 20069 000

r

1

0.3

3

0.1

0.03

0.3

Paraffin Waxes

73 30072 20074 400

r

3

1

10

0.6

0.2

2

White Spirit and SBP

73 30072 20074 400

r

3

1

10

0.6

0.2

2

Other Petroleum Products

73 30072 20074 400

r

3

1

10

0.6

0.2

2

Anthracite

98 30094 600101 000

10

3

30

r

1.5

0.5

5

Coking Coal

94 60087 300101 000

10

3

30

r

1.5

0.5

5

Other Oil

Refinery Feedstocks

Other Bituminous Coal

94 60089 50099 700

10

3

30

r

1.5

0.5

5

Sub-Bituminous Coal

96 10092 800100 000

10

3

30

r

1.5

0.5

5

Lignite

101 000

90 900115 000

10

3

30

r

1.5

0.5

5

Oil Shale and Tar Sands

107 000

90 200125 000

10

3

30

r

1.5

0.5

5

Brown Coal Briquettes

n 97 500

87 300109 000

n 10

3

30

n

1.5

0.5

5

97 50087 300109 000

10

3

30

r

1.5

0.5

5

Coke Oven Coke and Lignite
Coke

r 107 000

95 700119 000

10

3

30

r

1.5

0.5

5

Gas Coker 107 000

95 700119 000

0.3

3

0.03

0.3

n 80 700

68 200Gas Works Gas

n 44 400

37 300Coke Oven Gas

n 44 400

37 300Blast Furnace Gas

n260 000

Oxygen Steel Furnace Gas

Coke

Patent Fuel

Derived Gases

Coal Tar

Natural Gas

2.18

r

1

0.1

95 300

n

10

3

30

0.5

5

54 100

r

1

0.3

3

0.1

0.03

0.3

54 100

r

1

0.3

3

0.1

0.03

0.3

219 000

308 000

r

1

0.3

3

0.1

0.03

0.3

n 182 000

145 000

202 000

r

1

0.3

3

0.1

0.03

0.3

56 10054 30058 300

r

1

0.3

3

0.1

0.03

0.3

n

1.5

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.3 (CONTINUED)DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN MANUFACTURING INDUSTRIES AND CONSTRUCTION(kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

CH4

N2O

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

Municipal Wastes (non-biomass fraction)n 91 700

73 300121 000

30

10

100

4

1.5

15

Industrial Wastes

n143 000

110 000

183 000

30

10

100

4

1.5

15

Waste Oilsn 73 300

72 20074 400

30

10

100

4

1.5

15

106 000

100 000

108 000

2

0.6

6

0.5

5

30

10

100

1.5

15

3

1

18

1

21

30

10

100

1.5

15

Peat

Other
Gas
non-fossil Biomass
fuels

LiquidBiofuels

Solid Biofuels

Wood / Wood Waste

n

n

1.5

n 112 000

95 000132 000aSulphite lyes (Black Liquor)n 95 300

80 700110 000

Other Primary Solid Biomassn 100 000

84 700117 000

Charcoaln 112 000

95 000132 000

70

600

4

1.5

15

Biogasoline

n 70 800

59 80084 300

r

3

1

10

0.6

0.2

2

Biodiesels

n 70 800

59 80084 300

r

3

1

10

0.6

0.2

2

Other Liquid Biofuels

n 79 600

67 10095 300

r

3

1

10

0.6

0.2

2

Landfill Gas

n 54 600

46 20066 000

r

1

0.3

3

0.1

0.03

0.3

Sludge Gas

n 54 600

46 20066 000

r

1

0.3

3

0.1

0.03

0.3

Other Biogas

n 54 600

46 20066 000

r

1

0.3

3

0.1

0.03

0.3

Municipal Wastes (biomass
fraction)

n100 000

84 700117 000

10

100

4

1.5

15

n

200

30

4
n

2
4

(a) Includes the biomass-derived CO2 emitted from the black liquor combustion unit and the biomass-derived CO2 emitted from the kraft mill lime kiln.
nindicates a new emission factor which was not present in the 1996 Guidelinesr
indicates an emission factor that has been revised since the 1996 Guidelines

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.19

Volume 2: Energy

TABLE 2.4
DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN THE COMMERCIAL/INSTITUTIONAL CATEGORY(kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

CH4

N2O

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

73 30071 10075 500

10

3

30

0.6

0.2

2

Crude Oilr

77 00069 30085 400

10

3

30

0.6

0.2

2

Natural Gas Liquidsr

64 20058 30070 400

10

3

30

0.6

0.2

2

Motor Gasoliner

69 30067 50073 000

10

3

30

0.6

0.2

2

Aviation Gasoliner

70 00067 50073 000

10

3

30

0.6

0.2

2

Jet Gasoliner

70 00067 50073 000

10

3

30

0.6

0.2

2

Gasoline

Orimulsion

Jet Kerosene

71 50069 70074 400

10

3

30

0.6

0.2

2

Other Kerosene

71 90070 80073 700

10

3

30

0.6

0.2

2

Shale Oil

73 30067 80079 200

10

3

30

0.6

0.2

2

Gas/Diesel Oil

74 10072 60074 800

10

3

30

0.6

0.2

2

Residual Fuel Oil

77 40075 50078 800

10

3

30

0.6

0.2

2

Liquefied Petroleum Gases

63 10061 60065 600

5

1.5

15

0.1

0.03

0.3

Ethane61 60056 50068 600

5

1.5

15

0.1

0.03

0.3

Naphtha73 30069 30076 300

10

3

30

0.6

0.2

2

Bitumen80 70073 00089 900

10

3

30

0.6

0.2

2

Lubricants

73 30071 90075 200

10

3

30

0.6

0.2

2

97 50082 900115 000

10

3

30

0.6

0.2

2

Refinery Feedstocks

73 30068 90076 600

10

3

30

0.6

0.2

2

Refinery Gas

n 57 600

48 20069 000

5

1.5

15

0.1

0.03

0.3

Paraffin Waxes

73 30072 20074 400

10

3

30

0.6

0.2

2

White Spirit and SBP

73 30072 20074 400

10

3

30

0.6

0.2

2

Other Petroleum
Products

73 30072 20074 400

10

3

30

0.6

0.2

2

Anthraciter 98 300

94 600101 000

10

3

30

1.5

0.5

5

Coking Coal

94 60087 300101 000

10

3

30

1.5

0.5

5

Other Bituminous Coal

94 60089 50099 700

10

3

30

1.5

0.5

5

Sub-Bituminous Coal

96 10092 800100 000

10

3

30

1.5

0.5

5

Lignite

101 000

90 900115 000

10

3

30

1.5

0.5

5

Oil Shale and Tar Sands

107 000

90 200125 000

10

3

30

1.5

0.5

5

Other OilPetroleum Coke

Brown Coal Briquettesr

97 50087 300109 000

n 10

3

30

r

1.5

0.5

5

97 50087 300109 000

10

3

30

n

1.5

0.5

5

Coke Oven Coke andLignite Coken 107 000

95 700119 000

10

3

30

1.5

0.5

4

Gas Coken 107 000

95 700119 000

5

1.5

15

0.1

0.03

0.3

Patent Fuel

Coke

r

2.20

n

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.4 (CONTINUED)DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN THE COMMERCIAL/INSTITUTIONAL CATEGORY(kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

N2O

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

n 80 700

68 20095 300

n 10

30

30

Gas Works Gas

n 44 400

37 30054 1005

1.5

Coke Oven Gas

n 44 400

37 30054 1005

1.5

Blast Furnace Gas

n 260 000

219 000

308 000

5

Oxygen Steel FurnaceGas

n 182 000

145 000

202 000

56 10054 300Coal Tar

Derived Gases

CH4

Natural Gas

Default
Emission
Factor

Lower

Upper

1.5

0.5

5

15

0.1

0.03

0.3

15

0.1

0.03

0.3

1.5

15

0.1

0.03

0.3

5

1.5

15

0.1

0.03

0.3

58 300

5

1.5

15

0.1

0.03

0.3

n

Municipal Wastes (nonbiomass fraction)n

91 70073 300121 000

300

100

900

4

1.5

15

Industrial Wastes

n 143 000

110 000

183 000

300

100

900

4

1.5

15

Waste Oilsn

73 30072 20074 400

300

100

900

4

1.5

15

106 000

100 000

108 000

n 10

3

30

1.4

0.5

5

Wood / Wood Waster 112 000

95 000132 000

300

100

900

4

1.5

15

Sulphite lyes (Black
Liquor)an

95 30080 700110 000

3

1

18

2

1

21

Other Primary Solid
Biomassn 100 000

84 700117 000

300

100

900

4

1.5

15

Charcoaln 112 000

95 000132 000

200

70

600

1

0.3

3

Biogasoline

n 70 800

59 80084 300

10

3

30

0.6

0.2

2

Biodiesels

n 70 800

59 80084 300

10

3

30

0.6

0.2

2

Other Liquid Biofuels

n 79 600

67 10095 300

10

3

30

0.6

0.2

2

Landfill Gas

n

54 60046 20066 000

5

1.5

15

0.1

0.03

0.3

Sludge Gas

n 54 600

46 20066 000

5

1.5

15

0.1

0.03

0.3

Other Biogasn

54 60046 20066 000

5

1.5

15

0.1

0.03

0.3

unicipal Wastes(biomass fraction)n 100 000

84 700117 000

100

900

4

1..5

15

Other
nonf ilM

Gas
Biomass

LiquidBiofuels

Solid Biofuels

Peat

n

300

n

n

(a) Includes the biomass-derived CO2 emitted from the black liquor combustion unit and the biomass-derived CO2 emitted from the kraft mill lime kiln.
nindicates a new emission factor which was not present in the 1996 Guidelinesr
indicates an emission factor that has been revised since the 1996 Guidelines

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.21

Volume 2: Energy

TABLE 2.5
DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN THE RESIDENTIAL AND AGRICULTURE/FORESTRY/FISHING/FISHINGFARMS CATEGORIES (kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

CH4

N2O

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

73 30071 10075 500

10

3

30

0.6

0.2

2

Crude Oilr

77 00069 30085 400

10

3

30

0.6

0.2

2

Natural Gas Liquids

r 64 200

58 30070 400

10

3

30

0.6

0.2

2

Motor Gasoliner

69 30067 50073 000

10

3

30

0.6

0.2

2

Aviation Gasoliner

70 00067 50073 000

10

3

30

0.6

0.2

2

Jet Gasoliner

70 00067 50073 000

10

3

30

0.6

0.2

2

Jet Kerosene

r 71 500

69 70074 400

10

3

30

0.6

0.2

2

Other Kerosene

71 90070 80073 700

10

3

30

0.6

0.2

2

Shale Oil

73 30067 80079 200

10

3

30

0.6

0.2

2

Gas/Diesel Oil

74 10072 60074 800

10

3

30

0.6

0.2

2

Gasoline

Orimulsion

Residual Fuel Oil

77 40075 50078 800

10

3

30

0.6

0.2

2

Liquefied Petroleum Gases

63 10061 60065 600

5

1.5

15

0.1

0.03

0.3

Ethane61 60056 50068 600

5

1.5

15

0.1

0.03

0.3

Naphtha73 30069 30076 300

10

3

30

0.6

0.2

2

Bitumen80 70073 00089 900

10

3

30

0.6

0.2

2

Lubricants

73 30071 90075 200

10

3

30

0.6

0.2

2

97 50082 900115 000

10

3

30

0.6

0.2

2

Petroleum Coker

Refinery Feedstocks

73 30068 90076 600

10

3

30

0.6

0.2

2

n 57 600

48 20069 000

5

1.5

15

0.1

0.03

0.3

Paraffin Waxes

73 30072 20074 400

10

3

30

0.6

0.2

2

White Spirit and SBP

73 30072 20074 400

10

3

30

0.6

0.2

3

Other Petroleum
Products

73 30072 20074 400

10

3

30

0.6

0.2

2

98 30094 600101 000

300

100

900

1.5

0.5

5

Other Oil

Refinery Gas

Anthracite
Coking Coal

94 60087 300101 000

300

100

900

1.5

0.5

5

Other Bituminous Coal

94 60089 50099 700

300

100

900

1.5

0.5

5

Sub-Bituminous Coal

96 10092 800100 000

300

100

900

1.5

0.5

5

Lignite

101 000

90 900115 000

300

100

900

1.5

0.5

5

Oil Shale and Tar Sands

107 000

90 200125 000

300

100

900

1.5

0.5

5

97 50087 300109 000

n 300

100

900

1.5

0.5

5

97 50087 300109 000

300

100

900

1.5

0.5

5

Coke Oven Coke andLignite Coker 107 000

95 700119 000

300

100

900

1.5

0.5

5

Gas Coker 107 000

95 700119 000

r

5

1.5

15

0.03

0.3

n 80 700

68 20095 300

n 300

100

900

0.5

5

Gas Works Gas

n 44 400

37 30054 100

5

1.5

15

0.1

0.03

0.3

Coke Oven Gas

n 44 400

37 30054 100

5

1.5

15

0.1

0.03

0.3

Blast Furnace Gas

n 260 000

219 000

308 000

5

1.5

15

0.1

0.03

0.3

Oxygen Steel
Furnace Gas

n 182 000

145 000

202 000

5

1.5

15

0.1

0.03

0.3

Brown Coal Briquettes

Coke

Patent Fuel

Derived Gases

Coal Tar

2.22

n

n

n

0.1
n

1.5

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.5 (CONTINUED)DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN THE RESIDENTIAL AND AGRICULTURE/FORESTRY/FISHING/FISHINGFARMS CATEGORIES (kg of greenhouse gas per TJ on a Net Calorific Basis)
CO2
Fuel

CH4

N2O

Default
Emission
Factor

Lower

Upper

Default
Emission
Factor

Lower

Upper

56 10054 30058 3005

1.5

91 70073 300121 000

300

Natural Gas

Default
Emission
Factor

Lower

Upper

15

0.1

0.03

0.3

100

900

4

1.5

15

Municipal Wastes (nonbiomass fraction)nIndustrial Wastes

n 143 000

110 000

183 000

300

100

900

4

1.5

15

Waste Oilsn

73 30072 20074 400

300

100

900

4

1.5

15

106 000

100 000

108 000

n 300

100

900

1.4

0.5

5

Wood / Wood Wasten 112 000

95 000132 000

300

100

900

4

1.5

15

Sulphite lyes (Black
Liquor)an

95 30080 700110 000

3

1

18

2

1

21

Other Primary Solid
Biomassn 100 000

84 700117 000

300

100

900

4

1.5

15

Charcoaln 112 000

95 000132 000

200

70

600

1

0.3

3

Biogasolinen70 80059 80084 300

10

3

30

0.6

0.2

2

Biodieselsn70 80059 80084 300

10

3

30

0.6

0.2

2

Other Liquid
Biofuelsr

79 60067 10095 300

10

3

30

0.6

0.2

2

Landfill Gas

n

54 60046 20066 000

5

1.5

15

0.1

0.03

0.3

Sludge Gasn

54 60046 20066 000

5

1.5

15

0.1

0.03

0.3

Other Biogasn

54 60046 20066 000

5

1.5

15

0.1

0.03

0.3

Municipal Wastes(biomass fraction)n 100 000

84 700117 000

300

100

900

4

1.5

15

Other nonfossil fuels

Gas Biomass

LiquidBiofuels

Solid Biofuels

Peat

n

n

n

(a) Includes the biomass-derived CO2 emitted from the black liquor combustion unit and the biomass-derived CO2 emitted from the kraft mill limekiln.
nindicates a new emission factor which was not present in the 1996 IPCC Guidelines.
r
indicates an emission factor that has been revised since the 1996I PCC Guidelines.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.23

Volume 2: Energy

2.3.2.2

T IER 2 COUNTRY - SPECIFIC EMISSION FACTORSGood practice is to use the most disaggregated, technology-specific and country-specific emission factors
available, particularly those derived from direct measurements at the different stationary combustion sources.
When using the Tier 2 approach, two possible types of emission factors exist:•

National emission factors: These emission factors may be developed by national programmes alreadymeasuring emissions of indirect greenhouse gases such as NOx, CO and NMVOCs for local air quality;•

Regional emission factors.

Chapter 2 of Volume 1 provides general guidance for acquiring and compiling information from different
sources, specific guidance for generating new data (Section 2.2.3) and generic guidance on emission factors(Section 2.2.4). When measurements are used to obtain emission factors, it is good practice to test a reasonable
number of sources representing the average conditions in the country including fuel type and composition, typeand size of the combustion unit, firing conditions, load, type of control technologies and maintenance level.

2.3.2.3

T IER 3 TECHNOLOGY - SPECIFIC EMISSION FACTORS

Due to the nature of the emissions of non-CO2 greenhouse gases, technology-specific emission factors areneeded for Tier 3. Tables 2.6 to 2.10 give, for example purposes, give representative emission factors for CH4
and N2O by main technology and fuel type. National experts working on detailed bottom-up inventories may use
these factors as a starting point or for comparison. They show uncontrolled emission factors for each of thetechnologies indicated. These emission factor data, therefore, do not include the level of control technology thatmight 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.

2.3.3

Choice of activity data

For Stationary Combustion, the activity data for all tiers are the amounts and types of fuel combusted. Most fuelsconsumers (enterprises, small commercial consumers, or households) normally pay for the solid, liquid andgaseous fuels they consume. Therefore, the masses or volumes of fuels they consume are measured or metered.
Quantities of carbon dioxide can normally be easily calculated from fuel consumption data and the carbon
contents of the fuels, taking into account the fraction of carbon unoxidised.
The quantities of non-CO2 greenhouse gases formed during combustion depend on the combustion technology
used, and therefore detailed statistics on fuel combustion technology are needed to rigorously estimate emissionsof non-CO2 greenhouse gases.
The amount and types of fuel combusted are obtained from one, or a combination, of the sources in the list
below:•

national energy statistics agencies (national energy statistics agencies may collect data on the amount andtypes of fuel combusted from individual enterprises that consume fuels)•

reports provided by enterprises to national energy statistics agencies (these reports are most likely to be
produced by the operators or owners of large combustion plants)•

reports provided by enterprises to regulatory agencies (for example, reports produced to demonstrate howenterprises are complying with emission control regulations)•individuals within the enterprise responsible for the combustion equipment•

periodic surveys, by statistical agencies, of the types and quantities of fuels consumed by a sample ofenterprises•

suppliers of fuels (who may record the quantities of fuels delivered to their customers, and may also record
the identity of their customers usually as an economic activity code).

2.24

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.6
UTILITY SOURCE EMISSION FACTORSEmission factors1(kg/TJ energy input)
Basic technology

Configuration

CH4

N2O

Liquid Fuels
Residual
Boilers

Fuel

Oil/Shale

Oil

Gas/Diesel Oil Boilers

Normal Firing

r

0.8

0.3

Tangential Firing

r

0.8

0.3

Normal Firing

0.9

0.4

Tangential Firing

0.9

0.4

4

NA

Large Diesel Oil Engines >600hp(447kW)
Solid Fuels
Pulverised
Bituminous
Combustion Boilers

Bituminous
Boilers

SpreaderStokerBituminous
Combustor

Fluidised

Bed

Dry Bottom, wall fired

0.7

r

0.5

Dry Bottom, tangentially fired

0.7

r

1.4

Wet Bottom

0.9

r

1.4

With and without re-injection

1

r

0.7

Circulating Bed

1

r

61

Bubbling Bed

1

r

61

Bituminous Cyclone Furnace

0.2

Lignite Atmospheric Fluidised
Bed

NA

1.6
r

71

Natural Gas
Boilers

r

1

n

1

Gas-Fired Gas Turbines >3MW

r

4

n

1

Large Dual-Fuel Engines

r 258

Combined Cyclen1

Circulating Bed

n

3

7

Bubbling Bed

n

3

3

Wood/Wood Waste Boilers3

n

11

n

7

Wood Recovery Boilers

n

1

n

1

NA
n

3

Peat
Peat Fluidised Bed Combustor2

Biomass

Source: US EPA, 2005b except otherwise indicated. Values were originally based on gross calorific value; they
were converted to net calorific value by assuming that net calorific values were 5 per cent lower than gross calorificvalues for coal and oil, and 10 per cent lower for natural gas. These percentage adjustments are the OECD/IEA
assumptions on how to convert from gross to net calorific values.
1

Source: Tsupari et al, 2006.

2

Values were originally based on gross calorific value; they were converted to net calorific value by assuming thatnet calorific value for dry wood was 20 per cent lower than the gross calorific value (Forest Product Laboratory,2004).

NA, data not available.
n indicates a new emission factor which was not present in the IPCC 1996 Guidelines
r indicates an emission factor that has been revised since the IPCC 1996 Guidelines

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.25

Volume 2: Energy

TABLE 2.7
INDUSTRIAL SOURCE EMISSION FACTORSEmission factors1(kg/TJ energy input)
Basic technology

Configuration

CH4

N2O

Residual Fuel Oil Boilers

3

0.3

Gas/Diesel Oil Boilers

0.2

0.4

Liquid Fuels

Large Stationary Diesel Oil Engines>600hp (447 kW)r

4Liquefied Petroleum Gases Boilers

n

0.9

NA
n

4

Solid Fuels
Other Bituminous/Sub-bit. Overfeed
Stoker Boilers

1

r

0.7

Other Bituminous/Sub-bit. Underfeed
Stoker Boilers

14

r

0.7

0.7

r

0.5

Dry Bottom, wall fired
Other Bituminous/Sub-bituminous
Pulverised

Dry Bottom, tangentially fired

0.7

r

1.4

Wet Bottom

0.9

r

1.4

1

r

0.7

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

Circulating Bed

1

r

61

Bubbling Bed

1

r

61

n

1

Natural Gas
Boilersr2

Gas-Fired Gas Turbines >3MW
Natural Gas-fired Reciprocating
Engines31412-Stroke Lean Burn

r 693

NA

4-Stroke Lean Burn

r 597

NA

4-Stroke Rich Burn

r 110

NA

Biomass
Wood/Wood Waste Boilers4

n 11

n

7

1

Source: US EPA, 2005b except otherwise indicated. Values were originally based on gross calorific value; they
were converted to net calorific value by assuming that net calorific values were 5 per cent lower than grosscalorific values for coal and oil, and 10 per cent lower for natural gas. These percentage adjustments are theOECD/IEA assumptions on how to convert from gross to net calorific values.

2

Factor was derived from units operating at high loads (80 percent load) only.

3

Most natural gas-fired reciprocating engines are used in the natural gas industry at pipeline compressor andstorage stations and at gas processing plants.

4

Values were originally based on gross calorific value; they were converted to net calorific value by assuming thatnet calorific value for dry wood was 20 per cent lower than the gross calorific value (Forest Product Laboratory,2004).

NA, data not available
n indicates a new emission factor which was not present in the IPCC 1996 Guidelines.
r indicates an emission factor that has been revised since the IPCC 1996 Guidelines .

2.26

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.8
KILNS, OVENS, AND DRYERS SOURCE EMISSION FACTORS
Industry

1

SourceEmission factors1(kg/TJ energy input
CH4

N2O

Cement, Lime

Kilns - Natural Gas

1.1

NA

Cement, Lime

Kilns - Oil

1.0

NA

Cement, Lime

Kilns - Coal

1.0

NA

Coking, Steel

Coke Oven

1.0

NA

Chemical Processes, Wood, Asphalt,
Copper, Phosphate

Dryer - Natural Gas

1.1

NA

Chemical Processes, Wood, Asphalt,
Copper, Phosphate

Dryer – Oil

1.0

NA

Chemical Processes, Wood, Asphalt,
Copper, Phosphate

Dryer – Coal

1.0

NA

Source: Radian, 1990. Values were originally based on gross calorific value; they were converted to net calorific value by
assuming that net calorific values 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 assumptions on how to convert from gross to net
calorific values.

NA, data not available.

There are a number of points of good practice that inventory compilers should follow when they collect and use
fuel consumption data. It is good practice to use, where possible, the quantities of fuel combusted rather than thequantities of fuel delivered. 9 Agencies collecting emission data from companies under an environmental
reporting regulation may request fuel combustion data on this basis. For further information on the generalframework for the derivation or review of activity data, check Chapter 2, Approaches to Data Collection, in
Volume 1.
Due to the technology-specific nature of emissions of non-CO2 greenhouse gases, detailed fuel combustion
technology statistics are needed in order to provide rigorous emission estimates. It is good practice to collectactivity data in units of fuel used, and to disaggregate as far as possible into the share of fuel used by major
technology types. Disaggregation can be achieved through a bottom-up survey of fuel consumption andcombustion technology, or through top-down allocations based on expert judgement and statistical sampling.
Specialised statistical offices or ministerial departments are generally in charge of regular data collection andhandling. Including representatives from these departments in the inventory process is likely to facilitate theacquisition of appropriate activity data. For some source categories (e.g. combustion in the Agriculture Sector),
there may be some difficulty in separating fuel used in stationary equipment from fuel used in mobile machinery.
Given the different emission factors for non-CO2 gases of these two sources, good practice is to derive shares ofenergy use of each of these sources by using indirect data (e.g. number of pumps, average consumption, needs
for water pumping etc.). Expert judgement and information available from other countries may also be relevant.
Good practice for electricity autoproduction (self-generation) is to assign emissions to the source categories (orsub-source categories) where they were generated and to identify them separately from those associated withother end-uses such as process heat. In many countries, the statistics related to autoproduction are available andregularly updated, so activity data should not represent a serious obstacle to estimating non-CO2 emissions.
Where confidentiality is an issue, direct discussion with the company affected often allows the data to be used.
Otherwise aggregation of the fuel consumption or emissions with those from other companies is usually
sufficient. For further information on dealing with restricted data sources or confidentiality issues, check Chapter
2, Approaches to Data Collection, in Volume 1.

9

Quantities of solid and liquid fuels delivered to enterprises will, in general, differ from quantities combusted. Thisdifference is normally the amount put into or taken from stocks held by the enterprise. Stock figures shown in national fuelbalances may not include stocks held by final consumers, or may include only stocks held by a particular source category(for example electricity producers). Delivery figures may also include quantities used for mobile sources or as feedstock.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.27

Volume 2: Energy

TABLE 2.9
RESIDENTIAL SOURCE EMISSION FACTORS
Basic technology

Emission factors1(kg/TJ energy input)

Configuration

CH4

N2O

Liquid Fuels
Residual Fuel Oil Combustors

1.4

NA

Gas/Diesel Oil Combustors

0.7

NA

Furnaces
Liquefied Petroleum Gas
Furnaces

5.8

0.2

1.1

Other Kerosene Stoves2
Liquified Petroleum Gas Stoves

2

NA

Wick

n

2.2 – 23

1.2 – 1.9

Standardn0.9 – 23

0.7 – 3.5

Solid Fuels
Anthracite Space Heaters
3

Other Bituminous Coal Stoves

Brick or Metal

r 147

NA

n 267 – 2650

NA

Natural Gas
Boilers and Furnaces

n

1

n

1

Biomass
Wood Pits4
Wood Stoves5, 6

200

NA

Conventional

r 932

NA

Non-catalytic

n 497

NA

r 360
n 258 – 2190

NA
4 – 18.5

NAnCatalytic
Wood Stoves7
6

Wood Fireplaces

9

Charcoal Stoves8n 275 – 386n1.6 – 9.3
Other Primary Solid Biomass
n 230 – 4190
n9.7
(Agriculture Wastes) Stoves9
Other Primary Solid Biomass
n 281
n 27
(Dung) Stoves10
1
Source: US EPA, 2005b except otherwise indicated. Values were originally based on gross calorific value; they wereconverted to net calorific value by assuming that net calorific values were 5 per cent lower than gross calorific values forcoal and oil, and 10 per cent lower for natural gas. These percentage adjustments are the OECD/IEA assumptions on how
to convert from gross to net calorific values.
2

Sources: Smith et al., 1992, 1993; Smith et al., 2000; Zhang et al., 2000. Results of experimental studies conducted on anumber of household stoves from China (CH4), India and Philippines (CH4 and N2O).

3

Source: Zhang et al., 2000. Results of experimental studies conducted on a number of household stoves from China.

4Source: Adapted from Radian, 1990; Revised IPCC 1996 Guidelines.

5

U.S. Stoves. Conventional stoves do not have any emission reduction technology or design features and, in most cases,
were manufactured before July 1, 1986.

6

Values were originally based on gross calorific value; they were converted to net calorific value by assuming that net
calorific value for dry wood was 20 per cent lower than the gross calorific value (Forest Product Laboratory, 2004).

7

Sources: Bhattacharya et al., 2002; Smith et al., 1992, 1993; Smith et al., 2000; Zhang et al., 2000. Results ofexperimental studies conducted on a number of traditional and improved stoves collected from: Cambodia, China, India,
Lao PDR, Malaysia, Nepal, Philippines and Thailand. N2O was measured only in the stoves from India and Philippines.
The values represent ultimate emission factors that take into account the combustion, at later stages, of charcoal produced
during earlier combustion stages.

8

Sources: Bhattacharya et al., 2002; Smith et al., 1992, 1993; Smith et al., 2000. Results of experimental studies conducted
on a number of traditional and improved stoves collected from: Cambodia, India, Lao PDR, Malaysia, Nepal, Philippines
and Thailand. N2O was measured only in the stoves from India and Philippines.

9

Sources: Smith et al, 2000; Zhang et al., 2000. Results of experimental studies conducted on a number of household stovesfrom China (CH4) and India (CH4 and N2O).

10Source: Smith et al., 2000. Results of experimental studies conducted on a number of household stoves from India.

NA, data not available.
n indicates a new emission factor which was not present in the IPCC 1996 Guidelines
r indicates an emission factor that has been revised since the IPCC 1996 Guidelines s

2.28

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

TABLE 2.10
COMMERCIAL/INSTITUTIONAL SOURCE EMISSION FACTORS
Basic technology

Emission factors1(kg/TJ energy input)

Configuration

CH4

N2O

Residual Fuel Oil Boilers

1.4

0.3

Gas/Diesel Oil Boilers

0.7

0.4

Liquid Fuels

Liquefied Petroleum Gases Boilers

n

0.9

n

4

Other Bituminous/Sub-bit. Overfeed
Stoker Boilers

n

1

n

0.7

Other Bituminous/Sub-bit. Underfeed
Stoker Boilers

n 14

n

0.7

Other Bituminous/Sub-bit. Hand-fed Units

n 87

n

0.7

Dry Bottom, wall fired

n

0.7

n

0.5

Dry Bottom, tangentially
fired

n

0.7

n

1.4

Wet Bottom

n

0.9

n

1.4

n

1

n

0.7

Circulating Bed

n

1

n 61

Bubbling Bed

n

1

n 61

Boilers

r

1

r

1

Gas-Fired Gas Turbines >3MWa

n

4

n

1.4

n 11

n

7

Solid Fuels

Other Bituminous/Sub-bituminous
Pulverised Boilers

Other Bituminous Spreader Stokers
Other Bituminous/Sub-bit. Fluidised Bed
Combustor
Natural Gas

Biomass
Wood/Wood Waste Boilers2
1

Source: US EPA, 2005b Values were originally based on gross calorific value; they were converted to net calorific value
by assuming that net calorific values were 5 per cent lower than gross calorific values for coal and oil, and 10 per centlower for natural gas. These percentage adjustments are the OECD/IEA assumptions on how to convert from gross to net
calorific values.

2

Values were originally based on gross calorific value; they were converted to net calorific value by assuming that net
calorific value for dry wood was 20 per cent lower than the gross calorific value (Forest Product Laboratory, 2004).

n indicates a new emission factor which was not present in the IPCC 1996 Guidelines
r indicates an emission factor that has been revised since the IPCC 1996 Guidelines

2.3.3.1

T IER 1 AND TIER 2

The activity data used in a Tier 1 approach for combustion in the energy sector are derived from energy statistics,
compiled by the national statistical agency. Comparable statistics are published by the International Energy
Agency (IEA), based on national returns. If national data are not directly available to the national inventory
compiler, a request could be sent to the IEA at stats@iea.org to receive the country’s data free of charge.
Primary data on fuel consumption are normally collected in mass or in volume units. Because the carbon content
of fuels is generally correlated with the energy content, and because the energy content of fuels is generally
measured, it is recommended to convert values for fuel consumption into energy units. Default values for theconversion of fuel consumption numbers into conventional energy units are given in section 1.4.1.2.
Information on energy statistics and balances methodology is available in the "Energy Statistics Manual"published by the IEA. This manual can be downloaded free of charge from www.iea.org. Key issues about more
important source categories are given below.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.29

Volume 2: Energy

EN ERGY INDUSTR IES
In energy industries, fossil fuels are both raw materials for the conversion processes, and sources of energy to
run these processes. The energy industry comprises three kinds of activities:
1

Primary fuel production (e.g. coal mining and oil and gas extraction);2

Conversion to secondary or tertiary fossil fuels (e.g. crude oil to petroleum products in refineries, coal
to coke and coke oven gas in coke ovens);3

Conversion to non-fossil energy vectors (e.g. from fossil fuel into electricity and/or heat).

Emissions from combustion during production and conversion processes are counted under energy industries.
Emissions from the secondary fuels produced by the energy industries are counted in the sector where they areused. When collecting activity data, it is essential to distinguish between the fuel that is combusted and the fuelthat is converted into a secondary or tertiary fuel in Energy Industries.
MA IN AC TIVITY ELEC TRIC I TY AND HEAT PRODUCTION
The main activity electricity and heat production (formerly known as public electricity and heat production)
converts the chemical energy stored in the fuels to either electrical power (counted under electricity generation)or heat (counted under heat production) or both (counted under combined heat and power, CHP); see Table 2.1.
Figure 2.2 shows the energy flows. In conventional power plants, the total energy losses to the environment
might be as high as 70 percent of the chemical energy in the fuels, depending on the fuel and the specifictechnology. In a modern high efficiency power plant, losses are down to about half of the chemical energy
contained in the fuels. In a combined heat and power plant most of the energy in the fuel is delivered to final
users, either as electricity or as heat (for industrial processes or residential heating or similar uses). The width of
the arrows roughly represents the relative magnitude of the energy flows involved.
Figure 2.2

Power and heat plants use fuels to produce electric power and/or useful heat.

Heat plant

Power plant

Energy losses

Energy losses

Combustion

Combustion
Heat out
Fuel In

Generator

Fuel In
Power out

Power & Heat
Energy losses
plant
EnergylossesCombustion
Fuel In

Generator

Heat out

Power Out

2.30

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

P ETRO LEUM R EFINI NG
In a petroleum refinery, crude oil is converted to a broad range of products (Figure 2.3). For this transformation
to occur, part of the energy content of the products obtained from crude oil is used in the refinery (See Table
2.1.). This complicates the derivation of activity data from energy statistics.
Figure 2.3

A refinery uses energy to transform crude oil into petroleum products.

RefineryPetroleum products out

Crude Oil In

Combustion

In principle all petroleum products are combustible as fuel to provide the process heat and steam needed for therefining processes. The petroleum products include a broad range from the heavy products like tar, bitumen,heavy fuel oils via the middle distillates like gas oils, naphtha, diesel oils, kerosenes to light products like motor
gasoline, LPG and refinery gas.
In many cases, the exact products and fuels used in refineries to produce the heat and steam needed to run therefinery processes are not easily derived from the energy statistics. The fuel combusted within petroleum
refineries typically amounts to 6 to 10 percent of the total fuel input to the refinery, depending on the complexityand vintage of the technology. It is good practice to ask the refinery industry for fuel consumption in order toselect or verify the appropriate values reported by energy statistics.
MANU FACTURIN G INDUSTR IES AND CONSTRUC TION
In manufacturing industries, raw materials are converted into products as is schematically presented in Figure 2.4.
For construction, the same principle holds: the inputs include the building materials and the outputs are thebuildings.
Manufacturing industries are generally classified according to the nature of their products. This is done via theInternational Standard Industrial Classification of economic activities that is used in Table 2.1 for convenientcross-referencing.
Figure 2.4

Fuels are used as an energy source in manufacturing industries to convert
raw materials into products. 10

Manufacturing Industry
Raw materials in

Fuels in10

Products out

Combustion

For some industries raw materials might include fossil fuel. Some fuel might be derived from by-products or waste streams
generated in the production process.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.31

Volume 2: Energy

Raw materials used in manufacturing industries can also include fossil fuels. Examples include production of
petrochemicals (eg methanol), other bulk chemicals (eg ammonia) and primary iron where coke is an input. In
some cases, the situation is more complicated, because the energy to drive the process might be directly
delivered from the chemical reactions of the manufacturing processes. An example of this is the manufacture ofprimary iron and steel, where the chemical reaction between the coke and the iron ore produces gas and heat thatare sufficient to run the process11. The reporting of emissions from gases obtained from processing feedstock andprocess fuels obtained directly from the feedstock (e.g. ammonia production) follows the principle stated in
Section 1.2 of this Volume and detailed guidance given in the IPPU Volume. In summary, if the emissions occur
in the IPPU source category which produced the gases emitted they remain as industrial processes emissions inthat source category. If the gases are exported to another source category in the IPPU sector, or to the energy
sector, then the fugitive, combustion or other emissions associated with them should be reported in the sector
where they occur. Inventory compilers are reminded to discriminate between emissions from processes where
the same fossil fuel is used both for energy and for feedstock purposes (e.g. synthesis gas production, carbon
black production), and to report these emissions in the correct sectors.
Some countries may face some difficulties in obtaining disaggregated activity data or may have different
definitions for industrial source categories. For example, some countries may include residential energy
consumption of the workers in industry consumption. In this case, any deviations from the definitions should be
documented.

2.3.3.2

T IER 3Tier 3 estimates incorporate data at the level of individual facilities, and this type of information is increasingly
available, because of the requirements of emissions trading schemes. It is often the case, that coverage of facility
level data does not correspond exactly to coverage of classifications within the national energy statistics, and thiscan give rise to difficulties in combining the various sources of information. Methods for combining data are
discussed in Chapter 2 of Volume 1 on General Guidance and Reporting.

2.3.3.3

A VOIDING DOUBLE COUNTING ACTIVITY DATA WITH
OTHER SECTORSThe use of fuel combustion statistics rather than fuel delivery statistics is key to avoid double counting inemission estimates. Fuel combustion data, however, are very seldom complete, since it is not practical tomeasure the fuel consumption or emissions of every residential or commercial source. Hence, national
inventories using this approach will generally contain a mixture of combustion data for larger sources anddelivery data for other sources. The inventory compiler must take care to avoid both double counting andomission of emissions when combining data from multiple sources.
When activity data are not quantities of fuel combusted but are instead deliveries to enterprises or mainsubcategories, there is a risk of double counting emissions from the IPPU or Waste Sectors. Identifying double
counting is not always easy. Fuels delivered and used in certain processes may give rise to by-products used asfuels elsewhere in the plant or sold for fuel use to third parties (e.g. blast furnace gas that is derived from cokeand other carbon inputs to blast furnaces). It is good practice to coordinate estimates between the stationary
source category and relevant industrial categories to avoid double counting or omissions. Some of the categories
and subcategories where fossil fuel carbon is reported and between which double counting of fossil fuel carbon
could, in principle, occur are summarized below.
•

IPPU – Production of non-fuel products from energy feedstocks such as coke, ethane, gas/diesel oil, LPG,
naphtha and natural gas.
The production of synthesis gas (syngas), namely the mixture of carbon monoxide and hydrogen, throughsteam reforming or partial oxidation of energy feedstocks deserves particular attention since these processes
produce CO2 emissions. Synthesis gas is an intermediate in the production of chemicals such as ammonia,
formaldehyde, methanol, pure carbon monoxide and pure hydrogen. Emissions from these processes shouldbe accounted for in the IPPU sector. Note that CO2 emissions should be counted at the point of emission if
the gas is stored for only a short time (e.g. CO2 used in the food and drink industry generated as a by productof ammonia production).

11

The best available techniques reference documents (BREFs) of the European Integrated Pollution Prevention and Control
Bureau (IPPC) for Iron and Steel (http://eippcb.jrc.es/) show that about one third of the heat requirement for the process
comes from the blast furnace gas produced and combusted in the blast air heaters. Also the heat produced by the
production of CO as the blast air passes over the coke is not strictly part of the reduction of the ore.

2.32

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

Synthesis gas is also produced by partial oxidation/gasification of solid and liquid fuel feedstocks in therelatively newer Integrated Gasification Combined Cycle (IGCC) technology for power generation. When
synthesis gas is produced in IGCC for the purpose of generating power, associated emissions should be
accounted for in 1A, fuel combustion.
In the production of carbides, CO2 is released when carbon-rich fuels, particularly petroleum coke, are used
as a carbon source. These emissions should be accounted for in the IPPU sector.
For further information, refer to Volume 3, which gives details of completeness check of carbon emissions
from feedstock and other non-energy use.
•

IPPU, AFOLU – Use of carbon as reducing agent in metal production
The greenhouse gas emissions originating from the use of coal, coke, natural gas, prebaked anodes and coalelectrodes as reducing agents in the commercial production of metals from ores should be accounted for in
the IPPU sector. Wood chips and charcoal may also be used in some of the processes. In this case, theresulting emissions are counted in the AFOLU sector. By-product fuels (coke oven gas and blast furnace gas)
are produced in some of these processes. These fuels may be sold or used within the plant. They may or may
not be included in the national energy balance. Care should consequently be taken not to double countemissions.

•

ENERGY, WASTE – methane from coal mine waste, landfill gas and sewage gas
In these cases, it is important to ensure that the amounts of fuel accounted for in stationary combustion are
the same as the quantities netted out from “Fugitive emissions from coal mining and handling”, “Waste
Incineration” and “Wastewater Treatment and Discharge” respectively.

•

WASTE – Incineration of waste
When energy is recovered from waste combustion, the associated greenhouse gas emissions are accounted
for in the Energy sector under stationary combustion. Waste incineration with no associated energy purposes
should be reported in the Waste source category; see Chapter 5 (Incineration and Open Burning of Waste) ofVolume 5. It is good practice to assess the content of waste and differentiate between the part containing
plastics and other fossil carbon materials from the biogenic part and estimate the associated emissions
accordingly. The CO2 emission from the fossil-carbon part can be included in the fuel category Other fuels,
while the CO2 emissions from the biomass part should be reported as an information item. For higher tierestimations, inventory compiler may refer to Chapter 5 of the Waste Volume. It is good practice to contact
those responsible for recovering used oils in order to assess the extent to which used oils are burned in the
country and estimate and report these emissions in the Energy sector if they are used as fuel.

•

ENERGY – Mobile combustion

The main issue is to ensure that double counting of agricultural and off-road vehicles is avoided.

2.3.3.4

T REATMENT OF BIOMASS

Biomass is a special case:•

Emissions of CO2 from biomass fuels are estimated and reported in the AFOLU sector as part of the
AFOLU methodology. In the reporting tables, emissions from combustion of biofuels are reported as
information items but not included in the sectoral or national totals to avoid double counting. In the emission
factor tables presented in this chapter, default CO2 emission factors are presented to enable the user toestimate these information items.

•

For biomass, only that part of the biomass that is combusted for energy purposes should be estimated forinclusion as an information item in the Energy sector.

•

The emissions of CH4 and N2O, however, are estimated and included in the sector and national totals
because their effect is in addition to the stock changes estimated in the AFOLU sector.

•

For fuel wood, activity data are available from the IEA or the FAO (Food and Agriculture Organisation of
the United Nations). These data originate from national sources and inventory compilers can obtain a better
understanding of national circumstances by contacting national statistical agencies to find the organisations
involved.

•

For agricultural crop residues (part of other primary solid biomass) and also for fuel wood, estimation
methods for activity data are available in Chapter 5 of the AFOLU volume.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.33

Volume 2: Energy•

In some instances, biofuels will be combusted jointly with fossil fuels. In this case, the split between thefossil and non-fossil fraction of the fuel should be established and the emission factors applied to theappropriate fractions.

2.3.4

Carbon dioxide capture

Capture and storage removes carbon dioxide from the gas streams that would otherwise be emitted to theatmosphere, and transfers it for indefinite long term storage in geological reservoirs, such as depleted oil and gas
fields or deep saline aquifers. In the energy sector, candidates for carbon dioxide capture and storage
undertakings include large stationary sources such as power stations and natural gas sweetening units. This
chapter deals only with CO2 capture associated with combustion activities, particularly those relative to power
plants. Fugitive emissions arising from the transfer of carbon dioxide from the point of capture to the geologicalstorage, and emissions from the storage site itself, are covered in Chapter 5 of this Volume. Other possibilities
also exist in industry to capture CO2 from process streams. These are covered in Volume 3.
There are three main approaches for capturing CO2 arising from the combustion of fossil fuels and/or biomass(Figure 2.5). Post-combustion capture refers to the removal of CO2 from flue gases produced by combustion of afuel (oil, coal, natural gas or biomass) in air. Pre-combustion capture involves the production of synthesis gas(syngas), namely the mixture of carbon monoxide and hydrogen, by reacting energy feedstocks with steam
and/or oxygen or air. The resulting carbon monoxide is reacted with steam by the shift reaction to produce CO2
and more hydrogen. The stream leaving the shift reactor is separated into a high purity CO2 stream and H2-richfuel that can be used in many applications, such as boilers, gas turbines and fuel cells.
Oxy-fuel combustion uses either almost pure oxygen or a mixture of almost pure oxygen and a CO2-rich
recycled flue gas instead of air for fuel combustion. The flue gas contains mainly H2O and CO2 with excess
oxygen required to ensure complete combustion of the fuel. It will also contain any other components in the fuel,any diluents in the oxygen stream supplied, any inert matter in the fuel and from air leakage into the system fromthe atmosphere. The net flue gas, after cooling to condense water vapour, contains from about 80 to 98 percent
CO2 depending on the fuel used and the particular oxy-fuel combustion process.
Figure 2.5

Oil
Coal
Gas
Biomass

CO 2 capture systems from stationary combustion sources
N2, O2(CO2)AirPower & Heat

Post-combustion
CO2

Compression

CO2 Separation

Dehydration

Pre-combustion

Steam
Gas - Light
hydrocarbons
Oil
Coal
Gas
Biomass

H2-richfuel

Reforming
Syngas

Air/O2
Steam

Partial
Oxidation /Gasification

Syngasreactor

CO2
Separation
CO2

Power & Heat

N2, O2(CO2)Air
Compression
Dehydration

N2, O2
(CO2)

Oil
Coal
Gas
Biomass

Shift

Power & Heat

Compression

Oxyfuel combustion

Dehydration

O2
Air

Air Separation

N2

Carbon dioxide capture has some energy requirements with a corresponding increase in fossil fuel consumption.
Also the capture process is less than 100 percent efficient, so a fraction of CO2 will still be emitted from the gas
stream. Chapter 3 of the IPCC Special Report on CO2 Capture and Storage (Thambimuthu et al., 2005) provides
a thorough overview of the current and emerging technologies for capturing CO2 from different streams arisingin the energy and the industrial processes sectors.

2.34

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

The general scheme concerning the carbon flows in the three approaches for capturing CO2 from streams arisingin combustion processes is depicted in Figure 2.6. The system boundary considered in this chapter includes thepower plant or other process of interest, the CO2 removal unit and compression/dehydration of the captured CO2
but does not include CO2 transport and storage systems. This general scheme also contemplates the possibility
that pre-combustion capture systems can also be applied to multi-product plants (also known as polygeneration
plants). The type of polygeneration plant considered in this chapter employs fossil fuel feedstocks to produce
electricity and/or heat plus a variety of co-products such as hydrogen, chemicals and liquid fuels. In those
processes associated with post-combustion and oxyfuel combustion capture systems, no carbonaceous coproducts are typically produced.
Figure 2.6

Carbon flows in and out of the system boundary for a CO 2 capture systemassociated with stationary combustion processes

Non-captured CO2(emitted)

Oil
Coal
Gas
Biomass

Power & Heat
+ CO2 separation

Captured CO2(to transport and storage)+ Compression & dehydration

Carbonaceous products(chemicals or liquid fuels)

The CO2 capture efficiency of any system represented in Figure 2.6 is given in Equation 2.6. Table 2.11
summarises estimates of CO2 capture efficiencies for post and pre-combustion systems of interest that have been
recently reported in several studies. This information is provided for illustrative purposes only as it is goodpractice to use measured data on volume captured rather than efficiency factors to estimate emissions from a
CO2 capture installation.

EQUATION 2.6
CO2 CAPTURE EFFICIENCY
Ccaptured CO2
EfficiencyCO2 capture technology =• 100
C fuel − C products
Where:
Efficiency CO 2 capture technology = CO2 capture system efficiency (percent)C captured CO 2

= amount of carbon in the captured CO2 stream (kg)C fuel= amount of carbon in fossil fuel or biomass input to the plant (kg)C products= amount of carbon in carbonaceous chemical or fuel products of the plant(kg).

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.35

Volume 2: Energy

TABLE 2.11
TYPICAL CO2 CAPTURE EFFICIENCIES FOR POST AND PRE-COMBUSTION SYSTEMSTechnologies

Efficiency (%)

References

Power plant / Capture system

Average

Minimum

Maximum

Pulverised subbituminous/bituminous coal
(250-760 MWe, 41-45% net
plant efficiency)1,2 / Aminebased post-combustion capture.

90

85

96

Alstom, 2001; Chen et al.,
2003; Gibbins et al., 2005;
IEA GHG, 2004; Parsons,
2002; Rao and Rubin, 2002;
Rubin et al., 2005; Simbeck,
2002; Singh et al., 2003.

Natural gas combined cycle(380-780 MWe, 55-58% net
plant efficiency, LHV)1 /Amine-based post-combustion
capture.

88

85

90

CCP, 2005; EPRI, 2002; IEA
GHG, 2004; NETL, 2002;
Rubin et al., 2005.

Integrated gasification
combined cycle (400-830 MWe,
31-40% net plant efficiency)1 /Physical solvent-based precombustion capture (Selexol)

88

85

91

IEA GHG, 2003; NETL,
2002; Nsakala et al., 2003;
Parsons, 2002; Rubin et al.,2005; Simbeck, 2002.

Electricity + H2 plant (coal,
2600-9900 GJ/hr input
capacity)1 / Physical solventbased pre-combustion capture(mostly Selexol)

83

80

90

Kreutz et al., 2005, Mitretek,
2003; NRC, 2004; Parsons,
2002.

Electricity + dimethyl ether(coal, 7900-8700 GJ/hr input
capacity)1 / Physical solventbased pre-combustion capture(Selexol or Rectisol)

64

32

97

Celik et al., 2005; Larson,
2003

Electricity + methanol (coal,
9900 GJ/hr input capacity)1 /Physical solvent-based precombustion capture (Selexol)

60

58

63

Larson, 2003

Electricity + Fischer-Tropschliquids (coal, 16000 GJ/hr input
capacity)1 / Physical solventbased pre-combustion capture(Selexol)

91

-

-

Mitretek, 2001

1

Reference plant without CO2 capture system

2

These options include existing plants with retrofitting post-combustion capture system as well as new designs integrating
power generation and capture systems.

TIER 3 CO 2 EMISSION ESTIMATES
Because this is an emerging technology, it requires plant-specific reporting at Tier 3. Plants, with capture andstorage will most probably meter the amount of gas removed by the gas stream and transferred to geologicalstorage. Capture efficiencies derived from the measured data can be compared with the values in Table 2.11 as averification cross-check.
Under Tier 3, the CO2 emissions are therefore estimated from the fuel consumption estimated as described inearlier sections of this chapter minus the metered amount removed.
EQUATION 2.7
TREATMENT OF CO2 CAPTURE
Emissions s = Pr oduction s − Capture s
Where:s2.36= source category or subcategory where capture takes place2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

Captures= Amount captured.

Productions= Estimated emissions, using these guidelines assuming no capture

Emissionss= Reported emission for the source category or sub-category

This method automatically takes into account any increase in energy consumption at the plant because of thecapture process (since this will be reflected in the fuel statistics), and it does not require independent estimationof the capture efficiency, since the residual emissions are estimated more accurately by the subtraction. If theplant is supplied with biofuels, the corresponding CO2 emissions will be zero (these are already included innational totals due to their treatment in the AFOLU sector), so the subtraction of the amount of gas transferred tolong-term storage may give negative emissions. This is correct since if the biomass carbon is permanently stored,
it is being removed from the atmosphere. The corollary of this is that any subsequent emissions from CO2transport, CO2 injection and the storage reservoir itself should be counted in national total emissions, irrespectiveof whether the carbon originates from fossil sources or recent biomass production. This is why in sections 5.3(CO2 transport), 5.4 (Injection) and 5.5 (Geological Storage) no reference is made to the origin of the CO2 storedin underground reservoirs. The metering for the amount removed should be installed in line with industrial
practice and will normally be accurate to about 1 percent.
Quantities of CO2 for later use and short-term storage should not be deducted from CO2 emissions except when
the CO2 emissions are accounted for elsewhere in the inventory12.

2.3.5

CompletenessA complete estimate of emissions from fuel combustion should include emissions from all fuels and all source
categories identified within the IPCC 2006 Guidelines. Completeness should be established by using the sameunderlying activity data to estimate emissions of CO2, CH4 and N2O from the same source categories.
All fuels delivered by fuel producers must be accounted for. Misclassification of enterprises and the use of
distributors to supply small commercial customers and households increase the chance of systematic errors in the
allocation of fuel delivery statistics. Where sample survey data that provide figures for fuel consumption by
specific economic sectors exist, the figures may be compared with the corresponding delivery data. Any
systematic difference should be identified and the adjustment to the allocation of delivery data may then be madeaccordingly.
Systematic under-reporting of solid and liquid fuels may also occur if final consumers import fuels directly.
Direct imports will be included in customs data and therefore in fuel supply statistics, but not in the statistics offuel deliveries provided by national suppliers. If direct importing by consumers is significant, then the statisticaldifference between supplies and deliveries will reveal the magnitude. Own use of fuels supplied by dedicatedmines may occur in such sectors of manufacturing as iron and steel and cement, and is also a potential source ofunder-reporting. Once again, a comparison with consumption survey results will reveal which main source
categories are involved in direct importing. Concerning biomass fuels, the national energy statistics agencies
should be consulted about their use, including possible use of non-commercially traded biomass fuels.
Experience has shown that some activities such as change in producer stocks of fossil fuels and own fuelcombustion by energy industries may be poorly covered in existing inventories. This also applies to statistics onbiomass fuels and from waste combustion. Their presence should be specifically checked with statisticalagencies, sectoral experts and organisations as well as supplementary sources of data included if necessary.
Chapter 2 of Volume 1 covers data collection in general.

2.3.6

Developing a consistent time series and recalculation

Using a consistent method to estimate emissions is the main mechanism for ensuring time series consistency.
However, the variability in fuel quality over time is also important to consider within the limits of the national
fuel characterisation or the fuel types listed in Tables 2.2 to 2.5. This includes variation in carbon content,
typically reflected in variation in the calorific values used to convert the fuels from mass or volume units to theenergy units used in the estimation. It is good practice for inventory compilers to check that variations ofcalorific values over time are in fact reflected in the information used to construct the national energy statistics.

12

Examples include urea production (Volume 3, section 3.2) and the use of CO2 in methanol production (Volume 3, section
3.9) where the CO2 due to the final products is accounted for.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.37

Volume 2: Energy

Application of these IPCC 2006 Guidelines may result in revisions in some components of the emissions
inventory, such as emissions factors or the sectoral classification of some emissions. For example, thecomponent of emissions of CO2 from non-fuel use of fossil fuels will move from the Energy Sector under the
IPCC 1996 Guidelines to the IPPU sector under the IPCC 2006 Guidelines. Whereas the IPCC 1996 Guidelines
for the energy sector estimated total potential emissions from fossil-fuel use and then subtracted the portion of
the carbon that ended up stored in long-lived products, the IPCC 2006 Guidelines include all non-fuel uses in the
IPPU sector. This should result in slightly decreased CO2 emissions reported from the Energy sector andincreased emissions reported in the IPPU sector. For further information on ensuring a consistent time series,
check Chapter 5, Time Series Consistency, in Volume 1.

2.4

UNCERTAINTY ASSESSMENT

2.4.1

Emission factor uncertainties

For fossil fuel combustion, uncertainties in CO2 emission factors are relatively low. These emission factors are
determined by the carbon content of the fuel and thus there are physical constraints on the magnitude of theiruncertainty. However, it is important to note there are likely to be intrinsic differences in the uncertainties of
CO2 emission factors of petroleum products, coal and natural gas. Petroleum products typically conform to fairly
tight specifications which limit the possible range of carbon content and calorific value, and are also sourced
from a relatively small number of refineries and/or import terminals. Coal by contrast may be sourced frommines producing coals with a very wide range of carbon contents and calorific values and is mostly supplied
under contract to users who adapt their equipment to match the characteristics of the particular coal. Hence at thenational level, the single energy commodity "black coal" can have a range of CO2 emission factors.
Emission factors for CH4 and especially N2O are highly uncertain. High uncertainties in emission factors may beascribed to lack of relevant measurements and subsequent generalisations, uncertainties in measurements, or an
insufficient understanding of the emission generating process. Furthermore, due to stochastic variations inprocess conditions, a high variability of the real time emission factors for these gases might also occur (Pulles
and Heslinga, 2004). Such variability obviously will also contribute to the uncertainty in the emission estimates.
The uncertainties of emission factors are seldom known or accessible from empirical data. Consequently,
uncertainties are customarily derived from indirect sources or by means of expert judgements. The IPCC 1996
Guidelines (Table A1-1, Vol. I, p. A1.4) suggest an overall uncertainty value of 7 per cent for the CO2 emission
factors of Energy.
The default uncertainties shown in Table 2.12 derived from the EMEP/CORINAIR Guidebook ratings(EMEP/CORINAIR, 1999) may be used in the absence of country-specific estimates.
TABLE 2.12
DEFAULT UNCERTAINTY ESTIMATES FOR STATIONARY COMBUSTION EMISSION FACTORS
Sector

CH4

Public Power, co-generation and district heating
Commercial, Institutional and Residential combustion
Industrial combustion

50-150%50-150%50-150%N2O
Order of magnitude*
Order of magnitude
Order of magnitude* i.e. having an uncertainty range from one-tenth of the mean value to ten times the mean value.
Source: IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (2000)

While these default uncertainties can be used for the existing emission factors (whether country-specific or takenfrom the IPCC Guidelines), there may be additional uncertainties associated with applying emission factors thatare not representative of the combustion conditions in the country. Uncertainties can be lower than the values inTable 2.12 if country-specific emission factors are used. It is good practice to obtain estimates of these
uncertainties from national experts taking into account the guidance concerning expert judgements provided inVolume 1.
There is currently relatively little experience in assessing and compiling inventory uncertainties and moreexperience is needed to assess whether the few available results are typical and comparable, and what the main
weaknesses in such analyses are. Some articles addressing uncertainty assessment of greenhouse inventories
have recently appeared in the peer-reviewed literature. Rypdal and Winiwater (2001) evaluated the uncertainties
in greenhouse gas inventories and compared the results reported by five countries namely Austria (Winiwarter
and Rypdal, 2001), the Netherlands (van Amstel et al., 2000), Norway (Rypdal, 1999), UK (Baggott et al., 2005)

2.38

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustionand USA (EIA, 1999). More recently, Monni et al. (2004) evaluated the uncertainties in the Finnish greenhousegas emission inventory.
Tables 2.13 and 2.14 summarise the uncertainty assessments of emission factors for stationary combustion
reported in the studies noted above. To complement this information, the approaches and emission factors usedby each country as (reported in the corresponding 2003 National Greenhouse Gas Inventory submission to the
UNFCCC) have been added to Tables 2.13 and 2.14. It can be seen that higher tier approaches and a higher
number of country-specific (CS) emission factors were used for CO2 as compared to CH4 and N2O. Conversely,
lower tier approaches and greater reliance on default emission factors were used for N2O. This information isprovided primarily for illustrative purposes. These uncertainty ranges could be used as a starting point or forcomparison by national experts working on uncertainty assessment.
TABLE 2.13
SUMMARY OF UNCERTAINTY ASSESSMENT OF CO2 EMISSION FACTORS FOR STATIONARY COMBUSTION
SOURCES OF SELECTED COUNTRIES

95%
confidence
interval1

Distribution

Austria± 0.5

NorwayCountry

2003 GHG inventory submission2

References

Approach3

Emission factor4

NormalC

CS

Winiwarter andRypdal, 2001±3

NormalC

CS

Rypdal, 1999

The
Netherlands±2-

T2, CS

CS, PS

UK±2

NormalT2

CS

Baggott et al.,
2005

USA

±2

-

T1

CS

EIA, 1999

Austria± 0.5

NormalC

CS

Winiwarter andRypdal, 2001

Norway±7

NormalC

CS

Rypdal, 1999

The
Netherlands± 1-10-T2, CS

CS, PSUK± 1-6

NormalT2

CS

Baggott et al.,(2005)

USA

± 0-1

-

T1

CS

EIA, 1999

Normal

T2, CS

D, CS, PS

Monni et al.,
2004

Oil

Van Amstel et al.,2000

Coal, coke, gas

Van Amstel et al.,2000

Other fuels (mainly peat)
Finland±5

1

Data are given as upper and lower bounds of the 95 percent confidence interval, and expressed as percent relative to themean value.

2

The information in the columns is based on the 2003 National Greenhouse Gas Inventory submissions from Annex I
Parties to the UNFCCC.

3

Notation keys that specify the approach applied: T1 (IPCC Tier 1), T2 (IPCC Tier 2), T3 (IPCC Tier 3), C (CORINAIR),CS (Country-specific).

4

Notation keys that specify the emission factor used: D (IPCC default), C (CORINAIR), CS (Country-specific), PS (Plant
Specific).

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.39

Volume 2: Energy

TABLE 2.14
SUMMARY OF UNCERTAINTY ASSESSMENT OF CH4 AND N2O EMISSION FACTORS FOR STATIONARYCOMBUSTION SOURCES OF SELECTED COUNTRIESCountry95%
confidence
interval1

Distribution

2003 GHG inventory
submission2
3

References4

Approach

Emission factor

NormalC, CS

CS

Winiwarter andRypdal, 2001

CH4
Austria± 50

Finland-75 to +10β

T1, T2, CS

CS, PS

Monni et al., 2004

Norway-50 to + 100

Lognormal

T2, CS

D, CS, PS

Rypdal, 1999

The
Netherlands

± 25

-

T2, CS

CS, PS

Van Amstel et al.,
2000

UK

± 50

TruncatednormalT2

D, C, CS

Baggott et al.,
2005

USA

Order ofmagnitude

-

T1

D, CS

EIA, 1999

N2O
Austria± 20

NormalC, CS

CS

Winiwarter andRypdal, 2001

Finland-75 to +10

Beta

T1, T2, CS

CS, PS

Monni et al., 2004

Norway-66 to + 200

Beta

T1, T2

D, CS

Rypdal, 1999

The
Netherlands

± 75

-

T1, CSD, PS

Van Amstel et al.,
2000

UK

± 100 to
200

-

T2

D, C, CS

Baggott et al.,
2005

USA

-55 to + 200

-

T1

D, CS

EIA, 1999

1

Data are given as upper and lower bounds of the 95 percent confidence interval, and expressed as percent relative to themean value.

2

The information in the columns is based on the 2003 National Greenhouse Gas Inventory submissions from Annex I
Parties to the UNFCCC.

3

Notation keys that specify the approach applied: T1 (IPCC Tier 1), T2 (IPCC Tier 2), T3 (IPCC Tier 3), C (CORINAIR),CS (Country-specific).

4

Notation keys that specify the emission factor used: D (IPCC default), C (CORINAIR), CS (Country-specific), PS (PlantSpecific).

2.4.2

Activity data uncertainties

Statistics of fuel combusted at large sources obtained from direct measurement or obligatory reporting are likely
to be within 3 percent of the central estimate. For some energy intensive industries, combustion data are likely to
be more accurate. It is good practice to estimate the uncertainties in fuel consumption for the main subcategories in consultation with the sample survey designers, because the uncertainties depend on the quality ofthe survey design and the size of sample used.
In addition to any systematic bias in the activity data as a result of incomplete coverage of consumption of fuels,
the activity data will be subject to random errors in the data collection that will vary from year to year. Countries
with good data collection systems, including data quality control, may be expected to keep the random error in
total recorded energy use to about 2-3 percent of the annual figure. This range reflects the implicit confidence
limits on total energy demand seen in models using historical energy data and relating energy demand to
economic factors. Percentage errors for individual energy use activities can be much larger.
Overall uncertainty in activity data is a combination of both systematic and random errors. Most developed
countries prepare balances of fuel supply and deliveries and this provides a check on systematic errors. In thesecircumstances, overall systematic errors are likely to be small. Experts believe that the uncertainty resulting fromthe two errors combined is probably in the range of ±5 percent for most developed countries. For countries with

2.40

2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

less well-developed energy data systems, this could be considerably larger, probably about ±10 percent. Informal
activities may increase the uncertainty up to as much as 50 percent in some sectors for some countries.
Uncertainty ranges for stationary combustion activity data are shown in Table 2.15. This information may be
used when reporting uncertainties. It is good practice for inventory compilers to develop, if possible, countryspecific uncertainties using expert judgement and/or statistical analysis.
TABLE 2.15
LEVEL OF UNCERTAINTY ASSOCIATED WITH STATIONARY COMBUSTION ACTIVITY DATA
Well developed statistical systems

SectorLess developed statistical systems

Surveys

Extrapolation

Surveys

Extrapolation

Main activity electricity
and heat production

Less than 1%

3-5%

1-2%

5-10%

Commercial, institutional,
residential combustion

3-5%

5-10%

10-15%

15-25%

Industrial combustion(Energy intensive
industries)

2-3%

3-5%

2-3%

5-10%

Industrial combustion(others)

3-5%

5-10%

10-15%

15-20%

Biomass in small sources

10-30%

20-40%

30-60%

60-100%The inventory compiler should judge which type of statistical system best describes their national circumstances.
Source: IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (2000)

2.5

INVENTORY QUALITY ASSURANCE/QUALITYCONTROL QA/QC

Specific QA/QC procedures to optimise the quality of estimates of emissions from stationary combustion are
given in Table 2.16.

2.5.1

Reporting and Documentation

It is good practice to document and archive all information required to produce the national emissions inventory
estimates, as outlined in Chapter 8 of Volume 1. It is not practical to include all documentation in the inventory
report. However, the inventory should include summaries of methods used and references to data sources suchthat the reported emissions estimates are transparent and steps in their calculation can be retraced. Some
examples of specific documentation and reporting that are relevant to stationary combustion sources are
discussed below.
For all tiers, it is good practice to provide the sources of the energy data used and observations on thecompleteness of the data set. Most energy statistics are not considered confidential. If inventory compilers do notreport disaggregated data due to confidentiality concerns, it is good practice to explain the reasons for theseconcerns, and to report the data in a more aggregated form.
The current IPCC reporting format (spreadsheet tables, aggregate tables) tries to provide a balance between therequirement of transparency and the level of effort that is realistically achievable by most inventory compilers.
Good practice involves some additional effort to fulfil the transparency requirements completely. In particular, if
Tier 3 is used, additional tables showing the activity data that are directly associated with the emission factors
should be prepared.
For country-specific CO2 emission factors, it is good practice to provide the sources of the calorific values,
carbon content and oxidation factors (whether the default factor of 100 percent is used or a different value
depending on circumstances). For country- and technology-specific non-CO2 greenhouse gas estimates, it may
be necessary to cite different references or documents. It is good practice to provide citations for thesereferences, particularly if they describe new methodological developments or emission factors for particulartechnologies or national circumstances. For all country- and technology-specific emission factors, it is goodpractice to provide the date of the last revision and any verification of the accuracy.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.41

Volume 2: Energy

In those circumstances where double counting could occur, it is good practice to state clearly whether emission
estimates have been allocated to the Energy or to other sectors such as AFOLU, IPPU or Waste, to show that no
double counting has occurred.

2.6

WORKSHEETS

The four pages of the worksheets (Annex 1 of this Volume) for the Tier I Sectoral Approach should be filled infor each of the source categories indicated in Table 2.16. Only the amount of fuel combusted for energy purposes
should be included in column A of the worksheets. When filling in column A of the worksheets, the following
issues should be taken into account: 1) some fuels are used for purposes other than for combustion, 2) wastederived fuels are sometimes burned for energy purposes, and 3) some of the fuel combustion emissions should
be included in Industrial Processes. Table 1 in the Annex lists the main considerations that should be taken into
consideration in deciding what fraction of consumption should be included in the activity data for each fuel.
TABLE 2.16
LIST OF SOURCE CATEGORIES FOR STATIONARY COMBUSTION
Code

2.42

Name

1A1a

Main Activity Electricity and Heat Production

1A1b

Petroleum Refining

1A1c

Manufacture of Solid Fuels and Other Energy Industries

1A2a

Iron and Steel

1A2b

Non-Ferrous Metals

1A2c

Chemicals

1A2d

Pulp, Paper and Print

1A2e

Food Processing, Beverages and Tobacco

1A2f

Non-Metallic Minerals

1A2g

Transport Equipment

1A2h

Machinery

1A2i

Mining (excluding fuels) and Quarrying

1A2j

Wood and Wood Products

1A2k

Construction

1A2l

Textile and Leather

1A2m

Non-specified Industry

1A4a

Commercial / Institutional

1A4b

Residential

1A4c

Agriculture / Forestry / Fishing / Fish Farms (Stationary
combustion)

1A5a

Non-Specified Stationary

2006 IPCC Guidelines for National Greenhouse Gas Inventories

•

Activity data
check

•

•

If a Tier 2 approach with country-specific factors is used, the inventory
compiler should compare the result to emissions calculated using theTier 1 approach with default IPCC factors. This type of comparison may
require aggregating Tier 2 emissions to the same sector and fuelgroupings as the Tier 1 approach. The approach should be documented
and any discrepancies investigated.
If possible, the inventory compiler should compare the consistency ofthe calculations in relation to the maximum carbon content of fuels thatare combusted by stationary sources. Anticipated carbon balances should
be maintained throughout the combustion sectors.

Calculations of non- CO2 emissions from stationary combustion

The national agency in charge of energy statistics should construct, if resources permit, national commodity balances expressed in mass units, andconstruct mass balances of fuel conversion industries. The time series of statistical differences should be checked for systematic effects (indicated by thedifferences persistently having the same sign) and these effects eliminated where possible.
The national agency in charge of energy statistics should also construct, if resources permit, national energy balances expressed in energy units and energybalances of fuel conversion industries. The time series of statistical differences should be checked, and the calorific values cross-checked with the default
values given in the Introduction chapter. This step will only be of value where different calorific values for a particular fuel (for example, coal) are applied
to different headings in the balance (such as production, imports, coke ovens and households). Statistical differences that change in magnitude or sign
significantly from the corresponding mass values provide evidence of incorrect calorific values.
The inventory compiler should confirm that gross carbon supply in the Reference Approach has been adjusted for fossil fuel carbon from imported orexported non-fuel materials in countries where this is expected to be significant.
Energy statistics should be compared with those provided to international organisations to identify inconsistencies.
There may be routine collections of emissions and fuel combustion statistics at large combustion plants for pollution legislation purposes. If possible, theinventory compiler can use these plant-level data to cross-check national energy statistics for representativeness.
If secondary data from national organisations are used, the inventory compiler should ensure that these organisations have appropriate QA/QC
programmes in place.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

•

•
•

•

•

•

Comparisonof emission
estimates
using
different
approaches

The inventory compiler should compare estimates of CO2 emissions
from fuel combustion prepared using the Sectoral Approach with theReference Approach, and account for any difference greater than orequal to 5 percent. In this comparative analysis, emissions from fuels
other than by combustion, that are accounted for in other sections of a
GHG inventory, should be subtracted from the Reference Approach.

Calculations of CO2 emissions from stationary combustion

Activity

TABLE 2.17
QA/QC PROCEDURES FOR STATIONARY SOURCES

2.43

Chapter 2: Stationary Combustion

The inventory compiler should carry out a review involving national experts and stakeholders in the different fields related to emissions from stationary
sources, such as: energy statistics, combustion efficiencies for different sectors and equipment types, fuel use and pollution controls. In developing
countries, expert review of emissions from biomass combustion is particularly important.

•External
review

2006 IPCC Guidelines for National Greenhouse Gas Inventories

CO2 capture should be reported only when linked with long-term
storage. The captured amounts should be checked with amount of CO2
stored. The reported CO2 captured should not exceed the amount of
stored CO2 plus reported fugitive emissions from the measure. The
amount of stored CO2 should be based on measurements of the amountinjected to storage.

•

CO2 capture

Not applicable

The inventory compiler should evaluate the quality control associatedwith facility-level fuel measurements that have been used to calculate
site-specific emission and oxidation factors. If it is established that there
is insufficient quality control associated with the measurements andanalysis used to derive the factor, continued use of the factor may bequestioned.

•

If direct measurements are used, the inventory compiler should ensurethat they are made according to good measurement practices including
appropriate QA/QC procedures. Direct measurements should becompared to the results derived from using IPCC default factors.

The inventory compiler should compare the emission factors used withsite or plant level factors, if these are available. This type of comparison
provides an indication of how reasonable and representative the national
factor is.

••

If country-specific emission factors are used, the inventory compiler
should compare them to the IPCC defaults, and explain and document
differences.

•

Calculations of non- CO2 emissions from stationary combustion

Evaluation of
directmeasurements

•

•

•

Emissionfactors checkand review

The inventory compiler should construct national energy balances
expressed in carbon units and carbon balances of fuel conversion
industries. The time series of statistical differences should be checked.
Statistical differences that change in magnitude or sign significantly
from the corresponding mass values provide evidence of incorrectcarbon content.
Monitoring systems at large combustion plants may be used to check theemission and oxidation factors in use at the plant.
Some countries estimate emissions from fuel consumed and the carbon
contents of those fuels. In this case, the carbon contents of the fuels
should be regularly reviewed.

Calculations of CO2 emissions from stationary combustion

TABLE 2.17(CONTINUED)
QA/QC PROCEDURES FOR STATIONARY SOURCES

Activity

Volume 2: Energy

2.44

Chapter 2: Stationary Combustion

References
Alstom Power Inc. (2001). ‘Engineering feasibility and economics of CO2 capture on an existing coal-fired
power plant’. Report No. PPL-01-CT-09 to Ohio Dept. of Development, Columbus and US Dept. ofEnergy/NETL, Pittsburgh.
Baggott, S.L., Brown, L., Milne, R., Murrells, T.P., Passant, N., Thistlethwaite, G. and Watterson, J.D. (2005).
‘UK Greenhouse Gas Inventory, 1990 to 2003 - Annual report for submission under the Framework
Convention on Climate Change’. National Environmental Technology Centre (Netcen), AEA Technology
plc, Building 551, Harwell, Didcot, Oxon., OX11 0QJ, UK. AEAT report AEAT/ENV/R/1971. ISBN 09547136-5-6. The work formed part of the Global Atmosphere Research Programme of the Department
for Environment, Food and Rural Affairs.
Battacharya, S.C., Albina, D.O. and Salam, P. Abdul (2002). ‘Emission factors of wood and charcoal-fired
cookstoves’. Biomass and Bioenergy, 23: 453-469
Celik, F., Larson, E.D. and. Williams R.H. (2005). ‘Transportation fuel from coal with low CO2 emissions.’
Wilson, M., T. Morris, J. Gale and K. Thambimuthu (eds.), Proceedings of 7th International Conferenceon Greenhouse Gas Control Technologies. Volume II: Papers, Posters and Panel Discussion, Elsevier
Science, Oxford UK (in press).
CCP (2005). ‘Economic and cost analysis for CO2 capture costs in the CO2 capture project, Scenarios’. In D.C.
Thomas (Ed.), Volume 1 - Capture and separation of carbon dioxide from combustion Sources, Elsevier
Science, Oxford, UK.
Chen, C., Rao, A.B. and Rubin, E.S. (2003). ‘Comparative assessment of CO2 capture options for existing coalfired power plants.’ presented at the Second National Conference on Carbon Sequestration, Alexandria,
VA, USA, 5-8 May.
EPRI (1993). Technical Assessment Guide, Volume 1: Electricity Supply-1993 (Revision 7), Electric Power
Research Institute, Palo Alto, CA, June.
EIA (1999). ‘Emissions of greenhouse gases in the United States of America’. (available at
http://www.eia.doe.gov/oiaf/1605/ggrpt).
Forest Products Laboratory (2004). Fuel value calculator, USDA Forest Service, Forest Products Laboratory,
Pellet Fuels Institute, Madison. (Available at http://www.fpl.fs.fed.us)Gibbins, J., Crane, R.I., Lambropoulos, D., Booth, C., Roberts, C.A. and Lord (2005). ‘Maximising theeffectiveness of post-combustion CO2 capture systems’. Proceedings of the 7 th International Conferenceon Greenhouse Gas Control Technologies. Volume I: Peer Reviewed Papers and Overviews, E.S. Rubin,
D.W. Keith, and C.F.Gilboy (eds.), Elsevier Science, Oxford, UK (in press).
IEA GHG (2003). ‘Potential for improvements in gasification combined cycle power generation with CO2
capture’, Report PH4/19, IEA Greenhouse Gas R&D Programme, Cheltenham, UK.
IEA GHG (2004). ‘Improvements in power generation with post-combustion capture of CO2.’ Report PH4/33,
Nov. 2004, IEA Greenhouse Gas R&D Programme, Cheltenham, UK.
Korhonen, S., Fabritius, M. and. Hoffren, H. (2001), ‘Methane and nitrous oxide emissions in the Finnish energy
production.’ Fortum publication Tech-4615. 36 pages.
(Available at http://www.energia.fi/attachment.asp?Section=1354&Item=1691)
Kreutz, T., Williams, R., Chiesa, P. and Consonni, S. (2005). ‘Co-production of hydrogen, electricity and CO2
from coal with commercially ready technology’. Part B: Economic analysis, International Journal of
Hydrogen Energy, 30 (7): 769-784.
Larson, E.D. and Ren, T. (2003). ‘Synthetic fuels production by indirect coal liquefaction’. Energy for
Sustainable Development, VII(4), 79-102.
Mitretek (2003). ‘Hydrogen from coal.’ Technical Paper MTR-2003-13, Prepared by D. Gray and G. Tomlinson
for the National Energy Technology Laboratory, US DOE, April.
Monni, S., Syri, S. and Savolainen, I. (2004). ‘Uncertainties in the Finnish greenhouse gas emission inventory.’
Environmental Science & Policy, 7: 87-98.
NETL (2002). ‘Advanced fossil power systems comparison study.’ Final report prepared for NETL by E.L.
Parsons (NETL, Morgantown, WV), W.W. Shelton and J.L. Lyons (EG&G Technical Services, Inc.,
Morgantown, WV), December.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.45

Volume 2: Energy

NRC (2004). ‘The hydrogen economy: opportunities, costs, barriers, and R&D needs’. Prepared by theCommittee on Alternatives and Strategies for Future Hydrogen Production and Use, Board on Energy andEnvironmental Systems of the National Research Council, The National Academies Press, Washington,
DC.
Nsakala, N., Liljedahl, G., Marion, J., Bozzuto, C., Andrus H. and Chamberland R. (2003). ‘Greenhouse gas
emissions control by oxygen firing in circulating fluidised bed boilers.’ Presented at the Second Annual
National Conference on Carbon Sequestration. Alexandria, VA, May 5-8.
Parsons Infrastructure & Technology Group, Inc. (2002). ‘Updated cost and performance estimates for fossil fuelpower plants with CO2 removal.’ Report under Contract No. DE-AM26-99FT40465 to U.S.DOE/NETL,
Pittsburgh, PA, and EPRI, Palo Alto, CA., December.
Pulles, T., and Heslinga, D. (2004). ‘On the variability of air pollutant emissions from gas-fired industrial
combustion plants.’ Atmospheric Environment, 38(23): 3829 - 3840.
Rao, A.B. and Rubin, E.S. (2002). ‘A technical, economic, and environmental assessment of amine-based CO2
capture technology for power plant greenhouse gas control’. Environmental Science and Technology, 36:
4467-4475.
Radian Corporation (1990). ‘Emissions and cost estimates for globally significant anthropogenic combustion
sources of NOx , N2O, CH4, CO, and CO2.’ Prepared for the Office of Research and Development, US
Environmental Protection Agency, Washington, D.C., USA.
Rubin, E.S., Rao, A.B. and Chen, C. (2005). ‘Comparative assessments of fossil fuel power plants with CO2
capture and storage.’ Proceedings of 7th International Conference on Greenhouse Gas Control
Technologies. Volume 1: Peer-Reviewed Papers and Overviews, E.S. Rubin, D.W. Keith and C.F. Gilboy(eds.), Elsevier Science, Oxford, UK (in press).
Rypdal, K. (1999). ‘An evaluation of the uncertainties in the national greenhouse gas inventory.’ SFT Report
99:01. Norwegian Pollution Control Authority, Oslo, Norway
Rypdal, K. and Winiwarter, W. (2001). ’Uncertainties in greenhouse gas emission inventories - evaluation,comparability and implications.’ Environmental Science & Policy, 4: 107–116.
Simbeck, D. (2002). ‘New power plant CO2 mitigation costs.’ SFA Pacific, Inc., Mountain View, CA.
Singh, D., Croiset, E. Douglas, P.L. and Douglas, M.A. (2003). ‘Techno-economic study of CO2 capture from anexisting coal-fired power plant: MEA scrubbing vs. O2/CO2 recycle combustion.’ Energy Conversion andManagement, 44: 3073-3091.
Smith K.R., Rasmussen, R.A., Manegdeg, F. and Apte, M. (1992). ‘Greenhouse gases from small-scale
combustion in developing countries: A Pilot Study in Manila.’ EPA/600/R-92-005, U.S. Environmental
Protection Agency, Research Triangle Park.
Smith K.R., M.A.K. Khalil, R.A. Rasmussen, M. Apte and F. Manegdeg (1993). ‘Greenhouse gases frombiomass fossil Fuels stoves in developing countries: a Manila Pilot Study.’ Chemosphere, 26(1-4): 479505.
Smith, K.R., Uma, R., Kishore, V.V.N, Lata, K., Joshi, V., Zhang, J., Rasmussen, R.A. and Khalil, M.A.K.
(2000). ‘Greenhouse gases from small-scale combustion devices in developing countries, Phase IIa:
Household Stoves in India.’ U.S. EPA/600/R-00-052, U.S. Environmental Protection Agency, Research
Triangle Park.
Thambimuthu, K., Soltanieh, M.,. Abanades, J.C., Allam, R., Bolland, O., Davison, J., Feron, P., Goede, F.,
Herrera, A., Iijima, M., Jansen, D., Leites, I., Mathieu, P., Rubin, E., Simbeck, D., Warmuzinski, K.,
Wilkinson, M., and Williams, R. (2005). Capture. In: IPCC Special Report on Carbon Dioxide Captureand Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change [Metz,
B., O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)]. Cambridge University Press,
Cambridge, United Kingdom and New York, NY, USA.
Tsupari, E., Tormonen, K., Monni, S., Vahlman, T., Kolsi, A. and Linna, V. (2006). Emission factors for nitrous
oxide (N2O) and methane (CH4) from Finnish power and heating plants and small-scale combustion. VTT,
Espoo, Finland. VTT Working Papers 43. (In Finnish with Engllish summary). See website:
http://www.vtt.fi/inf/pdf/workingpapers/2006/W43.pdf
U.S. EPA (2005a), Plain English Guide to the Part 75 Rule, U.S. Environmental Protection Agency, Clear Air
Markets Division, Washington, DC.
Available at: http://www.epa.gov/airmarkets/monitoring/ plain_english_guide_part75_rule.pdf

2.46

IPCC 2006 Guidelines for National Greenhouse Gas Inventories

Chapter 2: Stationary Combustion

U.S. EPA (2005b). Air CHIEF, Version 12, EPA 454/C-05-001, U.S. Environmental Protection Agency, Officeof Air Quality Planning and Standards, Washington, DC.
Available at: http:// http://www.epa.gov/ttn/chief/ap42/index.html
van Amstel, A., Olivier, J.G.J., Ruyssenaars, P. (Eds.) (2000). ‘Monitoring of greenhouse gases in the
Netherlands: Uncertainty and Priorities for improvement’ Proceedings of a National Workshop, Bilthoven,
The Netherlands, 1 September 1999. WIMEK:RIVM report 773201 003, July
Winiwarter, W. and Rypdal, K. (2001). ‘Assessing the uncertainty associated with a national greenhouse gas
emission inventory: a case study for Austria.’ Atmospheric Environment, 35: 5425-5440
Zhang, J., Smith, K.R., Ma, Y., Ye, S., Jiang, F., Qi, W., Liu, P., Khalil, M.A.K., Rasmussen, R.A. andThorneloe, S.A. (2000). ‘Greenhouse gases and other airborne pollutants from household stoves in China:
A database for emission factors.’ Atmospheric Environment, 34: 4537-4549.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

2.47