CHAPTER 2

STATIONARY COMBUSTION

* * *

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)

* * *

Contents

2 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

* * *

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 $ \\mathrm{C O\_{2}} $ capture efficiency.....2.35
Equation 2.7 Treatment of $ \\mathrm{C O\_{2}} $ capture.....2.36

$$
\\mathrm {C O} \_ {2}
$$

Figures

$$
\\mathrm {C O} \_ {2}
$$

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 and
construction (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 the
residential 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

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

* * *

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

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

Box

Box 2.1 Autoproducers .....2.11

* * *

2 STATIONARY COMBUSTION

2.1 OVERVIEW

This chapter describes the methods and data necessary to estimate emissions from Stationary Combustion, and
the categories in which these emissions should be reported. Methods are provided for the sectoral approach in
three 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-specific
emission factors; this includes the use of models and facility level emission data where available.

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 to
the stationary combustion information are summarised below.

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 use
of information from the database is the responsibility of greenhouse gas inventory compilers.

Content:

• A table detailing which sectors this chapter covers, and which IPCC source codes the emissions are to be
reported 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 both
the 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.

In the Sectoral Approach, emissions from stationary combustion are specified for a number of societal and
economic 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 and
construction (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 be
allocated to one of the other subcategories. Table 2.1 also indicates the mobile source categories in 1.A.4 and
1.A.5 that are treated in Chapter 3 of this Volume.

$$
\\mathrm {C O} \_ {2}, \\mathrm {C H} \_ {4}
$$

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

2.2 DESCRIPTION OF SOURCES

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

1
Available at [http://www.ipcc-nggip.iges.or.jp/efdb/main.php](http://www.ipcc-nggip.iges.or.jp/efdb/main.php)

* * *

TABLE 2.1

DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION2

| Code number and name |  |  |  | Definitions |
| --- | --- | --- | --- | --- |
| 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 away from the apparatus. |
| 1A1 | Energy Industries |  |  | Comprises emissions from fuels combusted by the fuel extraction or energy-producing industries. |
| 1A1 | a | Main Activity Electricity and Heat Production |  | Sum of emissions from main activity producers of electricity generation, combined heat and power generation, and heat plants. Main activity producers (formerly known as public utilities) are defined as those undertakings whose primary activity is to supply the public. They may be in public or private ownership. Emissions from own on-site use of fuel should be included. |
| Emissions from autoproducers (undertakings which generate electricity/heat wholly or partly for their own use, as an activity that supports their primary activity) should be assigned to the sector where they were generated and not under 1A1a. Autoproducers may be in public or private ownership. |  |  |  |  |
| 1A1 | a | i | Electricity Generation | Comprises emissions from all fuel use for electricity generation from main activity producers except those from combined heat and power plants. |
| 1A1 | a | ii | Combined Heat and Power Generation(CHP) | Emissions from production of both heat and electrical power from 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 by pipe network. |
| 1A1 | b | Petroleum Refining |  | All combustion activities supporting the refining of petroleum products including on-site combustion for the generation of electricity and heat for own use. Does not include evaporative emissions occurring at the refinery. These emissions should be reported separately under 1B2a. |

2
Methods for mobile sources occurring in sub-categories 1 A 4 and 1 A 5 are dealt with in Chapter 3 and the emissions are
reported under Stationary Combustion.

* * *

TABLE 2.1 (CONTINUED)

DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION3

| Code number and name |  |  |  | Definitions |
| --- | --- | --- | --- | --- |
| 1A1 | c | Manufacture of Solid Fuels and Other Energy Industries |  | Combustion emissions from fuel use during the manufacture of 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 the generation of electricity and heat for own use in these industries. |
| 1A1 | c | i | Manufacture of Solid Fuels | Emissions arising from fuel combustion for the production of coke, brown coal briquettes and patent fuel. |
| 1A1 | c | ii | Other Energy Industries | Combustion emissions arising from the energy-producing industries own (on-site) energy use not mentioned above or for which separate data are not available. This includes the emissions 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 under 1A3e. |
| 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 in coke ovens within the iron and steel industry should be reported under 1A1c and not within manufacturing industry. Emissions from the industry sector should be specified by sub-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(1A3). Emissions arising from off-road and other mobile machinery in industry should, if possible, be broken out as a separate subcategory. For each country,the emissions from the largest fuel-consuming industrial categories ISIC should be reported,as well as those from significant emitters of pollutants.A suggested list of categories is outlined below. |
| 1A2 | a | Iron and Steel |  | ISIC Group271和Class2731 |
| 1A2 | b | Non-Ferrous Metals |  | ISIC Group272和Class2732 |
| 1A2 | c | Chemicals |  | ISIC Division24 |
| 1A2 | d | Pulp,Paper and Print |  | ISIC Divisions21和22 |
| 1A2 | e | Food Processing,Beverages and Tobacco |  | ISIC Divisions15和16 |
| 1A2 | f | Non-Metallic Minerals |  | Includes products such as glass,c ceramic, cement,etc.;ISIC Division26 |
| 1A2 | g | Transport Equipment |  | ISIC Divisions34和35 |
| 1A2 | h | Machinery |  | Includes fabricated metal products,machinery and equipment other than transport equipment;ISIC Divisions28,29,30,31and32. |

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

* * *

TABLE 2.1 (CONTINUED)

DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION4

| Code number and name |  |  |  | Definitions |
| --- | --- | --- | --- | --- |
| 1A2 | i | Mining(excludingfuels)和Quarrying |  | ISIC Divisions13和14 |
| 1A2 | j | Wood and WoodProducts |  | ISIC Division20 |
| 1A2 | k | Construction |  | ISIC Division45 |
| 1A2 | l | Textile and Leather |  | ISIC Divisions17,18和19 |
| 1A2 | m | Non-specifiedIndustry |  | Any manufacturingindustry/constructionnotincludedaboveorforwhichseparatedataarenotavailable.IncludesISICDivisions25,33,36and37. |
| 1A4 | OtherSectors |  |  | Emissionsfromcombustionactivitiesasdescribedbelow,includingcombustionforthegenerationofelectricityandheatforownuseinthesesectors. |
| 1A4 | a | Commercial/Institutional |  | Emissionsfromfuelcombustionincommercialandinstitutionalbuildings;allactivitiesincludedinISICDivisions41,50,51,52,55,63-67,70-75,80,85,90-93and99. |
| 1A4 | b | Residential |  | Allemissionsfromfuelcombustioninhouseholds. |
| 1A4 | c | Agriculture/Forestry/Fishing/Fish farms |  | Emissionsfromfuelcombustioninagriculture,forestry,fishingandfishingindustriessuchasfishfarms.ActivitiesincludedinISICDivisions01,02and05.Highwayagriculturaltransportationisexcluded. |
| 1A4 | c | i | Stationary | Emissionsfromfuelscombustedinpumps,graindrying,horticulturalgreenhousesandotheragriculture,forestryorstationarycombustioninthefishingindustry. |
| 1A4 | c | ii | Off-roadVehiclesandOtherMachinery | Emissionsfromfuelscombustedintractionvehiclesonfarmlandandinforests. |
| 1A4 | c | iii | Fishing(mobilecombustion) | Emissionsfromfuelscombustedforinland,coastalanddeep-seafishing.Fishingshouldcovervesselsofallflagsthathaverefuelledinthecountry(includeinternationalfishing). |

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

* * *

TABLE 2.1 (CONTINUED)

DETAILED SECTOR SPLIT FOR STATIONARY COMBUSTION5

| Code number and name |  |  |  | Definitions |
| --- | --- | --- | --- | --- |
| 1A5 | Non-Specified |  |  | All remaining emissions from fuel combustion that are not specified elsewhere. Include emissions from fuel delivered to the military in the country and delivered to the military of other countries that are not engaged in multilateral operations. |
| 1A5 | a | Stationary |  | Emissions from fuel combustion in stationary sources that are not specified elsewhere. |
| 1A5 | b | Mobile |  | Emissions from vehicles and other machinery, marine and aviation (not included in 1A4cii or elsewhere). |
| 1A5 | b | i | Mobile(aviation component) | All remaining aviation emissions from fuel combustion that are not specified elsewhere. Include emissions from fuel delivered to the country's military as well as fuel delivered within that country but used by the militaries of other countries that are not engaged in multilateral operations. |
| 1A5 | b | ii | Mobile(water-borne component) | All remaining water-borne emissions from fuel combustion that are not specified elsewhere. Include emissions from fuel delivered to the country's military as well as fuel delivered within that country but used by the militaries of other countries that are not engaged in multilateral operations. |
| 1A5 | b | iii | Mobile(other) | All remaining emissions from mobile sources not included elsewhere. |
| Multilateral operations(Information item) |  |  |  | Emissions from fuels used in multilateral operations pursuant to the Charter of the United Nations. Include emissions from fuel delivered to the military in the country and delivered to the military of other countries. |

The category “Manufacturing industries and Construction” has been subdivided using the International Standard
6
Industrial Classification. This industrial classification is widely used in energy statistics. Note that this table
adds a number of industrial sectors in the category “Manufacturing Industries and Construction” to better align
to 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
Methods for mobile sources occurring in sub-categories 1 A 4 and 1 A 5 are dealt with in Chapter 3 and the emissions are
reported under Stationary Combustion.

6
International Standard Industrial Classification of all Economic Activities, United Nations, New York. The publication can
be downloaded from [http://unstats.un.org/unsd/cr/](http://unstats.un.org/unsd/cr/).

* * *

BOX 2.1
AUTOPRODUCERS

| Box2.1AUTOPRODUCERS |
| --- |
| 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. This should be contrasted with main activity producers who generate and sell electricity and/or heat as their 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. |
| TheIPCC2006GuidelinesfollowtheIPCC1996Guidelinesinattributingemissionsfromautoproductionto theindustrialorcommercialbranchesinwhichthegenerationactivityoccurred,ratherthanto1A1a.Category1A1aisformainactivityproducersonly. |
| Withthecomplexityofplantactivitiesandinter-relationships,theremaynotalwaysbeaclearseparationbetweenautoproducersandmainactivityproducers.Themostimportantissueisthatallfacilitiesbeaccountedunderthemostappropriatecategoryandinacompleteandconsistentmanner. |

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. This
should be contrasted with main activity producers who generate and sell electricity and/or heat as
their 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 consistent
manner.

2.3 METHODOLOGICAL ISSUES

This 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 an
estimate of emissions. Properly applied, the higher tiers should be more accurate.

In general, emissions of each greenhouse gas from stationary sources are calculated by multiplying fuel
consumption by the corresponding emission factor. In the Sectoral Approach, “Fuel Consumption” is estimated

from energy use statistics and is measured in terajoules. Fuel consumption data in mass or volume units must
first be converted into the energy content of these fuels. All tiers described below use the amount of fuel
combusted as the activity data. Section 1.4.1.2 of the Introduction chapter contains information on how to find
and apply energy statistics data. Different tiers can be applied for different fuels and gases, consistent with the
requirements of key category analysis and avoidance of double counting (see also the General Decision Tree in
section 1.3.1.2).

from energy use statistics and is measured in terajoules. Fuel consumption data in mass or volume units must
first be converted into the energy content of these fuels. All tiers described below use the amount of fuel
combusted as the activity data. Section 1.4.1.2 of the Introduction chapter contains information on how to find
and apply energy statistics data. Different tiers can be applied for different fuels and gases, consistent with the
requirements of key category analysis and avoidance of double counting (see also the General Decision Tree in

section 1.3.1.2).

2.3.1.1 TIER 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

EmissionsGHG ,fuel

Emission factors come from the default values provided together with associated uncertainty range in Section
2.3.2.1. The following equation is used:

GREENHOUSE GAS EMISSIONS FROM STATIONARY COMBUSTION

= emissions of a given GHG by type of fuel (kg GHG)

• A default emission factor

$$
E m i s s i o n s \_ {G H G, f u e l} = F u e l \\quad C o n s u m p t i o n \_ {f u e l} \\cdot E m i s s i o n \\quad F a c t o r \_ {G H G, f u e l}
$$

$$
\\mathrm {t i o n} \_ {\\mathrm {f u e l}}
$$

= amount of fuel combusted (TJ)

$$
\\mathrm {F a c t o r} \_ {\\mathrm {G H G , f u e l}}
$$

Emission FactorGHG,fuel

GHG,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.

* * *

To calculate the total emissions by gas from the source category, the emissions as calculated in Equation 2.1 are
summed over all fuels:

\| EQUATION 2.2

| TOTAL EMISSIONS BY GREENHOUSE GAS |  |
| --- | --- |
| Emissions $ _{GHG} $ = $\\sum_{fuels} Emissions\_{GHG,fuel}$ |  |

$$
E m i s s i o n s \_ {G H G} = \\sum\_ {f u e l s} E m i s s i o n s \_ {G H G, f u e l}
$$

2.3.1.2 TIER 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, for
example carbon contents of the fuels used, carbon oxidation factors, fuel quality and (for non-CO2 gases in
particular) 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 good
practice to compare any country-specific emission factor with the default ones given in Tables 2.2 to 2.5. If such
country-specific emission factors are outside the 95 percent confidence intervals, given for the default values, an
explanation 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-specific
value 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 that
arise when waste is incinerated for energy purposes.

2.3.1.3 TIER 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,

EQUATION 2.3

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 is
indicated by making the variables and parameters technology dependent. Technology here stands for any device,
combustion process or fuel property that might influence the emissions.

• control technology,

GREENHOUSE GAS EMISSIONS BY TECHNOLOGY
= Fuel Consumption • Emission Factor

• age of the equipment used to burn the fuel.

• quality of maintenance,

$$
E m i s s i o n s \_ {G H G, f u e l, t e n c h o l o g y} = F u e l C o n s u m p t i o n \_ {f u e l, t e n c h o l o g y} \\cdot E m i s s i o n F a c t o r \_ {G H G, f u e l, t e n c h o l o g y}
$$

* * *

EmissionsGHG gas,fuel, technology = emissions of a given GHG by type of fuel and technology (kg
GHG)

Fuel Consumptionfuel, technology

7
= amount 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 means
of 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

Where:

$$
Fuel Consumption \_ {fuel, technology} = Fuel Consumption \_ {fuel} \\cdot Penetration \_ {technology}
$$

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 for
differences 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 all
technologies applied in the source category.

## EQUATION 2.5

TECHNOLOGY-BASED EMISSION ESTIMATION
=∑ Fuel Consumption• Emission Factor

$$
E m i s s i o n s \_ {G H G, f u e l} = \\sum\_ {\\mathrm {t e n n o l o g i e s}} F u e l C o n s u m p t i o n \_ {f u e l, t e n n o l o g y} \\bullet E m i s s i o n F a c t o r \_ {G H G, f u e l, t e n n o l o g y}
$$

Application of a Tier 3 emission estimation approach requires:

Total emissions are again calculated by summing over all fuels (Equation 2.2).

• 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 the
equipment).

• 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 not
depend 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 be
based on fuel flow measurements and fuel chemistry or on flue gas flow measurements and flue gas chemistry
data. Continuous emissions monitoring (CEM) of flue gases is generally not justified for accurate measurement
of CO2 emissions alone (because of the comparatively high cost) but could be undertaken particularly when
monitors 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 monitoring
is 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

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {N O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

7
Fuel consumption could be expressed on a mass or volume basis, and emissions can be estimated as the product of fuel
consumption and an emission factor expressed on a compatible basis.

8
See for example: U.S. EPA (2005a).

* * *

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 DECISION TREES

The 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 of
stationary 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 indicates
a 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.

$$
\\mathrm {C O} \_ {2}, \\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

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, this
fraction 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 other
parameters 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.

$$
\\mathrm {C O} \_ {2}, \\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O},
$$

$$
\\mathrm {C O} \_ {2}
$$

2.3.2.1 TIER 1

This section presents for each of the fuels used in stationary sources a set of default emission factors for use in
Tier 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.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2} / \\mathrm {T J}
$$

$$
\\mathrm {C H} \_ {4}
$$

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 to
technologies 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.

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {C H} \_ {4}
$$

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 are
based on the IPCC 1996 Guidelines. These emission factors were established using the expert judgement of a
large group of inventory experts and are still considered valid. Since not many measurements of these types of
emission 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 that
are reported in the 1A category. These emission factors are provided in Section 3.3 of this Volume.

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

* * *

Figure 2.1

Generalised decision tree for estimating emissions from stationary
combustion

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.

* * *

TABLE 2.2

| Fuel |  | CO2 |  |  | CH4 |  |  | N2O |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |
| Crude Oil |  | 73 300 | 71 100 | 75 500 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Ortimulsion |  | r 77 000 | 69 300 | 85 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Natural Gas Liquids |  | r 64 200 | 58 300 | 70 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Gasoline | Motor Gasoline | r 69 300 | 67 500 | 73 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| r 70 000 | 67 500 | 73 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |  |  |
| r 70 000 | 67 500 | 73 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |  |  |
| Jet Kerosene |  | r 71 500 | 69 700 | 74 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Other Kerosene |  | 71 900 | 70 800 | 73 700 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Shale Oil |  | 73 300 | 67 800 | 79 200 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Gas/Diesel Oil |  | 74 100 | 72 600 | 74 800 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Residual Fuel Oil |  | 77 400 | 75 500 | 78 800 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Liquefied Petroleum Gases |  | 63 100 | 61 600 | 65 600 | r 1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Ethane |  | 61 600 | 56 500 | 68 600 | r 1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Naphtha |  | 73 300 | 69 300 | 76 300 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Bitumen |  | 80 700 | 73 000 | 89 900 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Lubricants |  | 73 300 | 71 900 | 75 200 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Petroleum Coke |  | r 97 500 | 82 900 | 115 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Refinery Feedstocks |  | 73 300 | 68 900 | 76 600 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Other Oil | Refinery Gas | n 57 600 | 48 200 | 69 000 | r 1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Paraffin Waxes | 73 300 | 72 200 | 74 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |  |

$$
\\mathrm {C O} \_ {2}
$$

* * *

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)

| Fuel |  | CO2 |  |  | CH4 |  |  | N2O |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |
| Municipal Wastes (non-biomass fraction) |  | n91700 | 73300 | 121000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Industrial Washes |  | n143000 | 110000 | 183000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Waste Oils |  | n73300 | 72200 | 74400 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Peat |  | 106000 | 100000 | 108000 | n1 | 0.3 | 3 | n1.5 | 0.5 | 5 |
| Solid Biofuels | Wood / Wood Waste | n112000 | 95000 | 132000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Sulphite Iyes(Black Liquor)a | n95300 | 80700 | 110000 | n3 | 1 | 18 | n2 | 1 | 21 |  |
| Other Primary Solid Biomass | n100000 | 84700 | 117000 | 30 | 10 | 100 | 4 | 1.5 | 15 |  |
| Charcoal | n112000 | 95000 | 132000 | 200 | 70 | 600 | 4 | 1.5 | 15 |  |
| Liquid Biofuels | Biogasoline | n70800 | 59800 | 84300 | r3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Biodiesels | n70800 | 59800 | 84300 | r3 | 1 | 10 | 0.6 | 0.2 | 2 |  |
| Other Liquid Biofuels | n79600 | 67100 | 95300 | r3 | 1 | 10 | 0.6 | 0.2 | 2 |  |
| Gas Biomass | Landfill Gas | n54600 | 46200 | 66000 | r1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Sludge Gas | n54600 | 46200 | 66000 | r1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |  |
| Other Biogas | n54600 | 46200 | 66000 | r1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |  |
| Other non-fossil fuels | Municipal Wastes(biomass fraction) | n100000 | 84700 | 117000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| (a) Includes the biomass-derived CO2emitted from the black liquor combustion unit and the biomass-derived CO2emitted from the kraft mill lime kiln.n indicates a new emission factor which was not present in the 1996 Guidelinesr indicates an emission factor that has been revised since the 1996 Guidelines |  |  |  |  |  |  |  |  |  |  |

$$
\\mathrm {C O} \_ {2}
$$

* * *

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)

| Fuel |  | CO2 |  |  | CH4 |  |  | N2O |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |
| Crude Oil |  | 73 300 | 71 100 | 75 500 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Orimulsion |  | r 77 000 | 69 300 | 85 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Natural Gas Liquids |  | r 64 200 | 58 300 | 70 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Gasoline | Motor Gasoline | r 69 300 | 67 500 | 73 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Aviation Gasoline | r 70 000 | 67 500 | 73 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |  |
| Jet Gasoline | r 70 000 | 67 500 | 73 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |  |
| Jet Kerosene |  | 71 500 | 69 700 | 74 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Other Kerosene |  | 71 900 | 70 800 | 73 700 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Shale Oil |  | 73 300 | 67 800 | 79 200 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Gas/Diesel Oil |  | 74 100 | 72 600 | 74 800 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Residual Fuel Oil |  | 77 400 | 75 500 | 78 800 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Liquefied Petroleum Gases |  | 63 100 | 61 600 | 65 600 | r 1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Ethane |  | 61 600 | 56 500 | 68 600 | r 1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Naphtha |  | 73 300 | 69 300 | 76 300 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Bitumen |  | 80 700 | 73 000 | 89 900 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Lubricants |  | 73 300 | 71 900 | 75 200 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Petroleum Coke |  | r 97 500 | 82 900 | 115 000 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Refinery Feedstocks |  | 73 300 | 68 900 | 76 600 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Other Oil | Refinery Gas | n 57 600 | 48 200 | 69 000 | r 1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Paraffin Waxes | 73 300 | 72 200 | 74 400 | r 3 | 1 | 10 | 0.6 | 0.2 | 2 |  |

$$
\\mathrm {C O} \_ {2}
$$

* * *

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)

| Fuel |  | CO2 |  |  | CH4 |  |  | N2O |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |
| Municipal Wastes(non-biomass fraction) |  | n91700 | 73300 | 121000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Industrial Washes |  | n143000 | 110000 | 183000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Waste Oils |  | n73300 | 72200 | 74400 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Peat |  | 106000 | 100000 | 108000 | n2 | 0.6 | 6 | n2 | 0.5 | 5 |
| Solid Biofuels | Wood/Wood Waste | n112000 | 95000 | 132000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| Sulphite lyes(Black Liquor)a | n95300 | 80700 | 110000 | n3 | 1 | 18 | n2 | 1 | 21 |  |
| Other Primary Solid Biomass | n100000 | 84700 | 117000 | 30 | 10 | 100 | 4 | 1.5 | 15 |  |
| Charcoal | n112000 | 95000 | 132000 | 200 | 70 | 600 | 4 | 1.5 | 15 |  |
| Liquid Biofuels | Biogasoline | n70800 | 59800 | 84300 | r3 | 1 | 10 | 0.6 | 0.2 | 2 |
| Biodiesels | n70800 | 59800 | 84300 | r3 | 1 | 10 | 0.6 | 0.2 | 2 |  |
| Other Liquid Biofuels | n79600 | 67100 | 95300 | r3 | 1 | 10 | 0.6 | 0.2 | 2 |  |
| Gas Biomass | Landfill Gas | n54600 | 46200 | 66000 | r1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |
| Sludge Gas | n54600 | 46200 | 66000 | r1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |  |
| Other Biogas | n54600 | 46200 | 66000 | r1 | 0.3 | 3 | 0.1 | 0.03 | 0.3 |  |
| Other non-fossil fuels | Municipal Wastes(biomass fraction) | n100000 | 84700 | 117000 | 30 | 10 | 100 | 4 | 1.5 | 15 |
| (a)Includes the biomass-derived CO2emitted from the black liquor combustion unit and the biomass-derived CO2emitted from the kraft mill lime kiln.n indicates a new emission factor which was not present in the 1996 Guidelinesr indicates an emission factor that has been revised since the 1996 Guidelines |  |  |  |  |  |  |  |  |  |  |

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

* * *

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)

| Fuel |  | CO2}$ |  |  | CH4}$ |  |  | N2O |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |
| Crude Oil |  | 73 300 | 71 100 | 75 500 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Orimulsion |  | r 77 000 | 69 300 | 85 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Natural Gas Liquids |  | r 64 200 | 58 300 | 70 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Gasoline | Motor Gasoline | r 69 300 | 67 500 | 73 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Aviation Gasoline | r 70 000 | 67 500 | 73 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Jet Gasoline | r 70 000 | 67 500 | 73 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Jet Kerosene |  | r 71 500 | 69 700 | 74 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Other Kerosene |  | 71 900 | 70 800 | 73 700 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Shale Oil |  | 73 300 | 67 800 | 79 200 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Gas/Diesel Oil |  | 74 100 | 72 600 | 74 800 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Residual Fuel Oil |  | 77 400 | 75 500 | 78 800 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Liquefied Petroleum Gases |  | 63 100 | 61 600 | 65 600 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Ethane |  | 61 600 | 56 500 | 68 600 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Naphtha |  | 73 300 | 69 300 | 76 300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Bitumen |  | 80 700 | 73 000 | 89 900 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Lubricants |  | 73 300 | 71 900 | 75 200 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Petroleum Coke |  | r 97 500 | 82 900 | 115 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Refinery Feedstocks |  | 73 300 | 68 900 | 76 600 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Other Oil | Refinery Gas | n 57 600 | 48 200 | 69 000 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Paraffin Waxes | 73 300 | 72 200 | 74 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

* * *

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)

| Fuel |  | CO2 |  |  | CH4 |  |  | N2O |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |
| Coal Tar |  | n 80 700 | 68 200 | 95 300 | n 10 | 30 | 30 | n 1.5 | 0.5 | 5 |
| Derived Gases | Gas Works Gas | n 44 400 | 37 300 | 54 100 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Coke Oven Gas | n 44 400 | 37 300 | 54 100 | 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 |  |
| Natural Gas |  | 56 100 | 54 300 | 58 300 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Municipal Wastes (non-biomass fraction) |  | n 91 700 | 73 300 | 121 000 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Industrial Wastes |  | n 143 000 | 110 000 | 183 000 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Waste Oils |  | n 73 300 | 72 200 | 74 400 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Peat |  | 106 000 | 100 000 | 108 000 | n 10 | 3 | 30 | n 1.4 | 0.5 | 5 |
| Solid Biofuels | Wood / Wood Waste | r 112 000 | 95 000 | 132 000 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Sulphite Iyes (Black Liquor)^{a}$ | $n 95 300 | 80 700 | 110 000 | n 3 | 1 | 18 | n 2 | 1 | 21 |  |
| Other Primary Solid Biomass | n 100 000 | 84 700 | 117 000 | 300 | 100 | 900 | 4 | 1.5 | 15 |  |
| Charcoal | n 112 000 | 95 000 | 132 000 | 200 | 70 | 600 | 1 | 0.3 | 3 |  |
| Liquid Biofuels | Biogasoline | n 70 800 | 59 800 | 84 300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Biodiesels | n 70 800 | 59 800 | 84 300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Other Liquid Biofuels | n 79 600 | 67 100 | 95 300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Gas Biomass | Landfill Gas | n 54 600 | 46 200 | 66 000 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Sludge Gas | n 54 600 | 46 200 | 66 000 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |  |

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {C O} \_ {2}
$$

* * *

TABLE 2.5

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

| Fuel |  |  | CO2 |  | CH4 |  |  | N2O |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |  |
| Crude Oil |  |  | 73 300 | 71 100 | 75 500 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Orimulsion |  |  | r 77 000 | 69 300 | 85 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Natural Gas Liquids |  |  | r 64 200 | 58 300 | 70 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Gasoline | Motor Gasoline |  | r 69 300 | 67 500 | 73 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Aviation Gasoline |  | r 70 000 | 67 500 | 73 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Jet Gasoline |  | r 70 000 | 67 500 | 73 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Jet Kerosene |  |  | r 71 500 | 69 700 | 74 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Other Kerosene |  |  | 71 900 | 70 800 | 73 700 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Shale Oil |  |  | 73 300 | 67 800 | 79 200 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Gas/Diesel Oil |  |  | 74 100 | 72 600 | 74 800 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Residual Fuel Oil |  |  | 77 400 | 75 500 | 78 800 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Liquefied Petroleum Gases |  |  | 63 100 | 61 600 | 65 600 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Ethane |  |  | 61 600 | 56 500 | 68 600 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Naphtha |  |  | 73 300 | 69 300 | 76 300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Bitumen |  |  | 80 700 | 73 000 | 89 900 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Lubricants |  |  | 73 300 | 71 900 | 75 200 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Petroleum Coke |  |  | r 97 500 | 82 900 | 115 000 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Refinery Feedstocks |  |  | 73 300 | 68 900 | 76 600 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Other Oil | Refinery Gas |  | n 57 600 | 48 200 | 69 000 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Paraffin Waxes |  | 73 300 | 72 200 | 74 400 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

* * *

TABLE 2.5 (CONTINUED)

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

| Fuel |  | CO2 |  |  | CH4 |  |  | N2O |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper | Default Emission Factor | Lower | Upper |  |  |
| Natural Gas |  | 56100 | 54300 | 58300 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Municipal Wastes (non-biomass fraction) |  | n91700 | 73300 | 121000 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Industrial Wastes |  | n143000 | 110000 | 183000 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Waste Oils |  | n73300 | 72200 | 74400 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Peat |  | 106000 | 100000 | 108000 | n300 | 100 | 900 | n1.4 | 0.5 | 5 |
| Solid Biofuels | Wood / Wood Waste | n112000 | 95000 | 132000 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| Sulphite lyes(Black Liquor)^{a}$ | $n95300 | 80700 | 110000 | n3 | 1 | 18 | n2 | 1 | 21 |  |
| Other Primary Solid Biomass | n100000 | 84700 | 117000 | 300 | 100 | 900 | 4 | 1.5 | 15 |  |
| Charcoal | n112000 | 95000 | 132000 | 200 | 70 | 600 | 1 | 0.3 | 3 |  |
| Liquid Biofuels | Biogasoline | n70800 | 59800 | 84300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |
| Biodiesels | n70800 | 59800 | 84300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Other Liquid Biofuels | r79600 | 67100 | 95300 | 10 | 3 | 30 | 0.6 | 0.2 | 2 |  |
| Gas Biomass | Landfill Gas | n54600 | 46200 | 66000 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |
| Sludge Gas | n54600 | 46200 | 66000 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |  |
| Other Biogas | n54600 | 46200 | 66000 | 5 | 1.5 | 15 | 0.1 | 0.03 | 0.3 |  |
| Other non-fossil fuels | Municipal Wastes(biomass fraction) | n100000 | 84700 | 117000 | 300 | 100 | 900 | 4 | 1.5 | 15 |
| (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.n indicates 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. |  |  |  |  |  |  |  |  |  |  |

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {C O} \_ {2}
$$

* * *

2.3.2.2 TIER 2 COUNTRY-SPECIFIC EMISSION FACTORS

Good 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 already
measuring 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, type
and size of the combustion unit, firing conditions, load, type of control technologies and maintenance level.

2.3.2.3 TIER 3 TECHNOLOGY-SPECIFIC EMISSION FACTORS

Due to the nature of the emissions of non-CO2 greenhouse gases, technology-specific emission factors are
needed 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 the
technologies indicated. These emission factor data, therefore, do not include the level of control technology that
might be in place in some countries. For instance, for use in countries where control policies have significantly
influenced the emission profile, either the individual factors or the final estimate will need to be adjusted.

$$
\\mathrm {n o n - C O} \_ {2}
$$

2.3.3 Choice of activity data

$$
\\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

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 emissions
of non-CO2 greenhouse gases.
The amount and types of fuel combusted are obtained from one, or a combination, of the sources in the list

$$
\\mathrm {C O} \_ {2}
$$

The amount and types of fuel combusted are obtained from one, or a combination, of the sources in the list
below:

$$
\\mathrm {n o n - C O} \_ {2}
$$

• 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 how
enterprises are complying with emission control regulations)

* * *

TABLE 2.6

| TABLE 2.6UTILITY SOURCE EMISSION FACTORS |  |  |  |
| --- | --- | --- | --- |
|  |  | Emission factors$^{1}$ (kg/TJ energy input) |  |
| Basic technology | Configuration | CH\_{4}$ | N\_{2}O}$ |
| Liquid Fuels |  |  |  |
| Residual Fuel Oil/Shale Oil Boilers | Normal Firing | r0.8 | 0.3 |
| Tangential Firing | r0.8 | 0.3 |  |
| Normal Firing | 0.9 | 0.4 |  |
| Gas/Diesel Oil Boilers | Normal Firing | 0.9 | 0.4 |
| Tangential Firing | 0.9 | 0.4 |  |
| Large Diesel Oil Engines>600hp(447kW) |  | 4 | NA |
| Solid Fuels |  |  |  |
| Pulverised Bituminous Combustion Boilers | Dry Bottom, wall fired | 0.7 | r0.5 |
| Dry Bottom, tangentially fired | 0.7 | r1.4 |  |
| Wet Bottom | 0.9 | r1.4 |  |
| Bituminous Spreader Stoker Boilers | With and without re-injection | 1 | r0.7 |
| Bituminous Fluidised Bed Combustor | Circulating Bed | 1 | r61 |
| Bubbling Bed | 1 | r61 |  |
| Bituminous Cyclone Furnace |  | 0.2 | 1.6 |
| Lignite Atmospheric Fluidised Bed |  | NA | r71 |
| Natural Gas |  |  |  |
| Boilers |  | r1 | n1 |
| Gas-Fired Gas Turbines>3MW |  | r4 | n1 |
| Large Dual-Fuel Engines |  | r258 | NA |
| Combined Cycle |  | n1 | n3 |
| Peat |  |  |  |
| Peat Fluidised Bed Combustor$^{2}$ | Circulating Bed | n3 | 7 |
| Bubbling Bed | n3 | 3 |  |
| Biomass |  |  |  |
| Wood/Wood Waste Boilers$^{1}$ |  | n11 | n7 |
| Wood Recovery Boilers |  | n1 | n1 |
| Source:US EPA,2005b except otherwise indicated。Values were originally based on gross calorific value;theywere 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。这些 percentage adjustments are the OECD/IEAassumptions 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;theywere 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 theIPCC 1996 Guidelinesr indicates an emission factor that has been revised since theIPCC 1996 Guidelines |  |  |  |

$$
\\mathrm {C H} \_ {4}
$$

* * *

TABLE 2.7

| TABLE 2.7INDUSTRIAL SOURCE EMISSION FACTORS |  |  |  |
| --- | --- | --- | --- |
|  |  | Emission factors¹(kg/TJ energy input) |  |
| Basic technology | Configuration | CH₄ | N₂O |
| Liquid Fuels |  |  |  |
| Residual Fuel Oil Boilers |  | 3 | 0.3 |
| Gas/Diesel Oil Boilers |  | 0.2 | 0.4 |
| Large Stationary Diesel Oil Engines >600hp (447 kW) |  | r 4 | NA |
| Liquefied Petroleum Gases Boilers |  | n 0.9 | 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 |
| Other Bituminous/Sub-bituminous Pulverised | 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 |  |
| Other Bituminous Spreader Stokers |  | 1 | r 0.7 |
| Other Bituminous/Sub-bit. Fluidised Bed Combustor | Circulating Bed | 1 | r 61 |
| Bubbling Bed | 1 | r 61 |  |
| Natural Gas |  |  |  |
| Boilers |  | r 1 | n 1 |
| Gas-Fired Gas Turbines² >3MW |  | 4 | 1 |
| Natural Gas-fired Reciprocating Engines³ | 2-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 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.$^{2}$ 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 and storage stations and at gas processing plants.$^{4}$ 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).NA, data not availablen 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. |  |  |  |

* * *

TABLE 2.8

KILNS, OVENS, AND DRYERS SOURCE EMISSION FACTORS

| Industry | Source | Emission 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 |
| $^{1}$ 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. |  |  |  |

$$
\\mathrm {C H} \_ {4}
$$

1
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 the
9
quantities of fuel delivered. Agencies collecting emission data from companies under an environmental
reporting regulation may request fuel combustion data on this basis. For further information on the general
framework 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
technology statistics are needed in order to provide rigorous emission estimates. It is good practice to collect
activity 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 and
combustion 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 and
handling. Including representatives from these departments in the inventory process is likely to facilitate the
acquisition 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 of
energy use of each of these sources by using indirect data (e.g. number of pumps, average consumption, needs

greenhouse gases, detailed fuel combustion
technology statistics are needed in order to provide rigorous emission estimates. It is good practice to collect
activity 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 and
combustion 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 and
handling. Including representatives from these departments in the inventory process is likely to facilitate the
acquisition 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.
gases of these two sources, good practice is to derive shares of
energy use of each of these sources by using indirect data (e.g. number of pumps, average consumption, needs

energy 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.

$$
\\mathrm {n o n - C O} \_ {2}
$$

$$
\\mathrm {n o n - C O} \_ {2}
$$

Good practice for electricity autoproduction (self-generation) is to assign emissions to the source categories (or
sub-source categories) where they were generated and to identify them separately from those associated with
other end-uses such as process heat. In many countries, the statistics related to autoproduction are available and
regularly 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.

$$
\\mathrm {C O} \_ {2}
$$

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. This
difference is normally the amount put into or taken from stocks held by the enterprise. Stock figures shown in national fuel
balances 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.

* * *

TABLE 2.9

| TABLE 2.9RESIDENTIAL SOURCE EMISSION FACTORS |  |  |  |
| --- | --- | --- | --- |
| Basic technology | Configuration | Emission factors$^{1}$ (kg/TJ energy input) |  |
| CH\_{4}$ | N\_{2}O}$ |  |  |
| Liquid Fuels |  |  |  |
| Residual Fuel Oil Combustors |  | 1.4 | NA |
| Gas/Diesel Oil Combustors |  | 0.7 | NA |
| Furnaces |  | 5.8 | 0.2 |
| Liquefied Petroleum Gas Furnaces |  | 1.1 | NA |
| Other Kerosene Stoves$^{2}$ | Wick | n2.2-23 | 1.2-1.9 |
| Liquified Petroleum Gas Stoves$^{2}$ | Standard | n0.9-23 | 0.7-3.5 |
| Solid Fuels |  |  |  |
| Anthracite Space Heaters |  | r147 | NA |
| Other Bituminous Coal Stoves$^{3}$ | Brick or Metal | n267-2650 | NA |
| Natural Gas |  |  |  |
| Boilers and Furnaces |  | n1 | n1 |
| Biomass |  |  |  |
| Wood Pits$^{4}$ |  | 200 | NA |
| Wood Stoves$^{5,6}$ | Conventional | r932 | NA |
| Non-catalytic | n497 | NA |  |
| Catalytic | r360 | NA |  |
| Wood Stoves$^{7}$ |  | n258-2190 | 4-18.5 |
| Wood Fireplaces$^{6}$ |  | NA | n9 |
| Charcoal Stoves$^{8}$ |  | n275-386 | n1.6-9.3 |
| Other Primary Solid Biomass(Agriculture Wastes) Stoves$^{9}$ |  | n230-4190 | n9.7 |
| Other Primary Solid Biomass(Dung) Stoves$^{10}$ |  | n281 | n27 |
| $^{1}$ 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 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. |  |  |  |
| $^{2}$ Source: Smith et al., 1992, 1993; Smith et al., 2000; Zhang et al., 2000. Results of experimental studies conducted on a number of household stoves from China(CH\_{4}), India and Philippines(CH\_{4}) and N\_{2}O). |  |  |  |
| $^{3}$ Source: Zhang et al., 2000. Results of experimental studies conducted on a number of household stoves from China. |  |  |  |
| $^{4}$ Source: 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. |  |  |  |
| $^{7}$ Source: Bhattacharya et al., 2002; Smith et al., 1992, 1993; Smith et al., 2000; Zhang et al., 2000. Results of experimental 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. |  |  |  |
| $^{8}$ Source: 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. |  |  |  |
| $^{9}$ Source: Smith et al., 2000; Zhang et al., 2000. Results of experimental studies conducted on a number of household stoves from China(CH\_{4}) and India(CH\_{4}) and N2O). |  |  |  |
| $^{10}$ Source: 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 Guidelinesr indicates an emission factor that has been revised since the IPCC 1996 Guideliness |  |  |  |

$$
\\mathrm {C H} \_ {4}
$$

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 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.
2
Sources: Smith et al., 1992, 1993; Smith et al., 2000; Zhang et al., 2000. Results of experimental studies conducted on a

$$
\\left(\\mathrm {C H} \_ {4}\\right)
$$

$$
\\left(\\mathrm {C H} \_ {4}\\right)
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O})
$$

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

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 of

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O})
$$

* * *

TABLE 2.10

| TABLE 2.10COMMERCIAL/INSTITUTIONAL SOURCE EMISSION FACTORS |  |  |  |
| --- | --- | --- | --- |
| Basic technology | Configuration | Emission factors$^{1}$ (kg/TJ energy input) |  |
| CH\_{4}$ | N\_{2}O}$ |  |  |
| Liquid Fuels |  |  |  |
| Residual Fuel Oil Boilers |  | 1.4 | 0.3 |
| Gas/Diesel Oil Boilers |  | 0.7 | 0.4 |
| Liquefied Petroleum Gases Boilers |  | n0.9 | n4 |
| Solid Fuels |  |  |  |
| Other Bituminous/Sub-bit. Overfeed Stoker Boilers |  | n1 | n0.7 |
| Other Bituminous/Sub-bit. Underfeed Stoker Boilers |  | n14 | n0.7 |
| Other Bituminous/Sub-bit. Hand-fed Units |  | n87 | n0.7 |
| Other Bituminous/Sub-bituminous Pulverised Boilers | Dry Bottom, wall fired | n0.7 | n0.5 |
| Dry Bottom, tangentially fired | n0.7 | n1.4 |  |
| Wet Bottom | n0.9 | n1.4 |  |
| Other Bituminous Spreader Stokers |  | n1 | n0.7 |
| Other Bituminous/Sub-bit. Fluidised Bed Combustor | Circulating Bed | n1 | n61 |
| Bubbling Bed | n1 | n61 |  |
| Natural Gas |  |  |  |
| Boilers |  | r1 | r1 |
| Gas-Fired Gas Turbines>3MWa |  | n4 | n1.4 |
| Biomass |  |  |  |
| Wood/Wood Waste Boilers$^2$ |  | n11 | n7 |

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

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 cent
lower 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

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

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

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 the
conversion of fuel consumption numbers into conventional energy units are given in section 1.4.1.2.

2.3.3.1 TIER 1 AND TIER 2

r indicates an emission factor that has been revised since the IPCC 1996 Guidelines

* * *

ENERGY INDUSTRIES

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 are
used. When collecting activity data, it is essential to distinguish between the fuel that is combusted and the fuel
that is converted into a secondary or tertiary fuel in Energy Industries.

MAIN ACTIVITY ELECTRICITY 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 specific
technology. 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.

* * *

PETROLEUM REFINING

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.

In principle all petroleum products are combustible as fuel to provide the process heat and steam needed for the
refining 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 the
refinery 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 complexity
and vintage of the technology. It is good practice to ask the refinery industry for fuel consumption in order to
select or verify the appropriate values reported by energy statistics.

MANUFACTURING INDUSTRIES AND CONSTRUCTION

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 the
buildings.

Manufacturing industries are generally classified according to the nature of their products. This is done via the
International Standard Industrial Classification of economic activities that is used in Table 2.1 for convenient
cross-referencing.

Figure 2.4

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

* * *

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 of
primary iron and steel, where the chemical reaction between the coke and the iron ore produces gas and heat that
are sufficient to run the process11. The reporting of emissions from gases obtained from processing feedstock and
process 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 in
that 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 TIER 3

Tier 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 this
can 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 AVOIDING DOUBLE COUNTING ACTIVITY DATA WITH
OTHER SECTORS

The use of fuel combustion statistics rather than fuel delivery statistics is key to avoid double counting in
emission estimates. Fuel combustion data, however, are very seldom complete, since it is not practical to
measure 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 and
delivery data for other sources. The inventory compiler must take care to avoid both double counting and
omission of emissions when combining data from multiple sources.

• 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, through
steam 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 should
be 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 product
of ammonia production).

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

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/](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.

* * *

Synthesis gas is also produced by partial oxidation/gasification of solid and liquid fuel feedstocks in the
relatively 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.

$$
\\mathrm {C O} \_ {2}
$$

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 coal
electrodes 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, the
resulting 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 count
emissions.

• 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) of
Volume 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 tier
estimations, 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

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

• ENERGY – Mobile combustion

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

• For biomass, only that part of the biomass that is combusted for energy purposes should be estimated for
inclusion 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

2.3.3.4 TREATMENT OF BIOMASS

Biomass is a special case:

$$
\\mathrm {C O} \_ {2}
$$

• 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 to
estimate these information items.

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

• 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.

* * *

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

2.3.4 Carbon dioxide capture

Capture and storage removes carbon dioxide from the gas streams that would otherwise be emitted to the
atmosphere, 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 geological
storage, 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.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

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 a
fuel (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-rich
fuel that can be used in many applications, such as boilers, gas turbines and fuel cells.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

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 from
the 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.

$$
\\mathrm {H} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {C O} \_ {2} - \\mathrm {r i c h}
$$

$$
\\mathrm {C O} \_ {2}
$$

Figure 2.5

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 arising
in the energy and the industrial processes sectors.

CO2 capture systems from stationary combustion sources

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

* * *

The general scheme concerning the carbon flows in the three approaches for capturing CO2 from streams arising
in combustion processes is depicted in Figure 2.6. The system boundary considered in this chapter includes the
power 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.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

Figure 2.6

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

$$
\\mathrm {C O} \_ {2}
$$

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 good
practice to use measured data on volume captured rather than efficiency factors to estimate emissions from a
CO2 capture installation.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

Where:

$$
\\mathrm {E f f i c i e n c y} \_ {\\mathrm {C O} \_ {2}}
$$

$$
= \\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C} \_ {\\mathrm {c a p t u r e d}} \\quad \\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C} \_ {\\mathrm {p r o d u c t s}}
$$

* * *

TABLE 2.11

TYPICAL CO2 CAPTURE EFFICIENCIES FOR POST AND PRE-COMBUSTION SYSTEMS

| Technologies | Efficiency(%) |  |  | References |
| --- | --- | --- | --- | --- |
| Power plant/Capture system | Average | Minimum | Maximum |  |
| Pulverised sub-bituminous/bituminous coal(250-760MWe,41-45% net plant efficiency)1,2/Amine-based post-combustion capture. | 90 | 85 | 96 | Alstom,2001;Chenet 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(380-780MWe,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(400-830MWe,31-40% net plant efficiency)1/Physical solvent-based pre-combustion capture(Selexol) | 88 | 85 | 91 | IEA GHG,2003;NETL,2002;Nsakala et al.,2003;Parsons,2002;Rubin et al.,2005;Simbeck,2002. |
| Electricity+H2plant(coal,2600-9900GJ/hr input capacity)1/Physical solvent-based pre-combustion capture(mostly Selexol) | 83 | 80 | 90 | Kreutz et al.,2005;Mitretek,2003;NRC,2004;Parsons,2002. |
| Electricity+dimethyl ether(coal,7900-8700GJ/hr input capacity)1/Physical solvent-based pre-combustion capture(Selexol or Rectisol) | 64 | 32 | 97 | Celik et al.,2005;Larson,2003 |
| Electricity+methanol(coal,9900GJ/hr input capacity)1/Physical solvent-based pre-combustion capture(Selexol) | 60 | 58 | 63 | Larson,2003 |
| Electricity+Fischer-Tropsch liquids(coal,16000GJ/hr input capacity)1/Physical solvent-based pre-combustion capture(Selexol) | 91 | - | - | Mitretek,2001 |
| 1Reference plant withoutCO2capture system |  |  |  |  |

$$
\\mathrm {C O} \_ {2}
$$

$$

- \\mathrm {H} \_ {2}
  $$

Under Tier 3, the CO2 emissions are therefore estimated from the fuel consumption estimated as described in
earlier sections of this chapter minus the metered amount removed.

TIER 3 CO2 EMISSION ESTIMATES

$$
\\mathrm {C O} \_ {2}
$$

Because this is an emerging technology, it requires plant-specific reporting at Tier 3. Plants, with capture and
storage will most probably meter the amount of gas removed by the gas stream and transferred to geological
storage. Capture efficiencies derived from the measured data can be compared with the values in Table 2.11 as a
verification cross-check.

\| EQUATION2.7
TREATMENT OFCO2CAPTURE

| Emissionss=Prductions-Captures |
| --- |

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.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

s = source category or subcategory where capture takes place

* * *

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 the
capture process (since this will be reflected in the fuel statistics), and it does not require independent estimation
of the capture efficiency, since the residual emissions are estimated more accurately by the subtraction. If the
plant is supplied with biofuels, the corresponding CO2 emissions will be zero (these are already included in
national totals due to their treatment in the AFOLU sector), so the subtraction of the amount of gas transferred to
long-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 CO2
transport, CO2 injection and the storage reservoir itself should be counted in national total emissions, irrespective
of 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 stored
in 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.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\left(\\mathrm {C O} \_ {2}\\right)
$$

Quantities of CO2 for later use and short-term storage should not be deducted from CO2 emissions except when
12
the CO2 emissions are accounted for elsewhere in the inventory.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

2.3.5 Completeness

A 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 same
underlying activity data to estimate emissions of CO2, CH4 and N2O from the same source categories.

$$
\\mathrm {f C O} \_ {2}, \\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

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 made
accordingly.
Systematic under-reporting of solid and liquid fuels may also occur if final consumers import fuels directly.

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 of
fuel deliveries provided by national suppliers. If direct importing by consumers is significant, then the statistical
difference between supplies and deliveries will reveal the magnitude. Own use of fuels supplied by dedicated
mines may occur in such sectors of manufacturing as iron and steel and cement, and is also a potential source of
under-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.

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 of
fuel deliveries provided by national suppliers. If direct importing by consumers is significant, then the statistical
difference between supplies and deliveries will reveal the magnitude. Own use of fuels supplied by dedicated
mines may occur in such sectors of manufacturing as iron and steel and cement, and is also a potential source of
under-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 fuel
combustion by energy industries may be poorly covered in existing inventories. This also applies to statistics on
biomass fuels and from waste combustion. Their presence should be specifically checked with statistical
agencies, sectoral experts and organisations as well as supplementary sources of data included if necessary.
Chapter 2 of Volume 1 covers data collection in general.

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 the
energy units used in the estimation. It is good practice for inventory compilers to check that variations of
calorific values over time are in fact reflected in the information used to construct the national energy statistics.

2.3.6 Developing a consistent time series and recalculation

$$
\\mathrm {C O} \_ {2}
$$

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.

$$
\\mathrm {C O} \_ {2}
$$

* * *

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, the
component 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 and
increased emissions reported in the IPPU sector. For further information on ensuring a consistent time series,
check Chapter 5, Time Series Consistency, in Volume 1.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

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 their
uncertainty. 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 from
mines 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 the
national level, the single energy commodity "black coal" can have a range of CO2 emission factors.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C O} \_ {2}
$$

Emission factors for CH4 and especially N2O are highly uncertain. High uncertainties in emission factors may be
ascribed 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 in
process 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.

$$
\\mathrm {C H} \_ {4}
$$

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

| TABLE 2.12DEFAULT UNCERTAINTY ESTIMATES FOR STATIONARY COMBUSTION EMISSION FACTORS |  |  |
| --- | --- | --- |
| Sector | CH4 | N2O |
| Public Power, co-generation and district heating | 50-150% | Order of magnitude\* |
| Commercial, Institutional and Residential combustion | 50-150% | Order of magnitude |
| Industrial combustion | 50-150% | Order of magnitude |
| $\\cdot$ 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) |  |  |

There is currently relatively little experience in assessing and compiling inventory uncertainties and more
experience 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)

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
I P C C
$$ and USA (EIA, 1999). More recently, Monni et al. (2004) evaluated the uncertainties in the Finnish greenhouse
gas 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 used
by 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 is
provided primarily for illustrative purposes. These uncertainty ranges could be used as a starting point or for
comparison by national experts working on uncertainty assessment.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

TABLE 2.13
CO

$$
\\mathrm {C O} \_ {2}
$$

\| TABLE 2.13

| SUMMARY OF UNCERTAINTY ASSESSMENT OF CO2 EMISSION FACTORS FOR STATIONARY COMBUSTION SOURCES OF SELECTED COUNTRIES |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- |
| Country | 95% confidence interval1 | Distribution | 2003 GHG inventory submission2 |  | References |
| Approach3 | Emission factor4 |  |  |  |  |
| Oil |  |  |  |  |  |
| Austria | $\\pm$0.5 | Normal | C | CS | Winiwarter and Rypdal, 2001 |
| Norway | $\\pm$3 | Normal | C | CS | Rypdal, 1999 |
| The Netherlands | $\\pm$2 | - | T2, CS | CS, PS | Van Amstel et al., 2000 |
| UK | $\\pm$2 | Normal | T2 | CS | Baggott et al., 2005 |
| USA | $\\pm$2 | - | T1 | CS | EIA, 1999 |
| Coal, coke, gas |  |  |  |  |  |
| Austria | $\\pm$0.5 | Normal | C | CS | Winiwarter and Rypdal, 2001 |
| Norway | $\\pm$7 | Normal | C | CS | Rypdal, 1999 |
| The Netherlands | $\\pm$1-10 | - | T2, CS | CS, PS | Van Amstel et al., 2000 |
| UK | $\\pm$1-6 | Normal | T2 | CS | Baggott et al., (2005) |
| USA | $\\pm$0-1 | - | T1 | CS | EIA, 1999 |
| Other fuels (mainly peat) |  |  |  |  |  |
| Finland | $\\pm$5 | Normal | T2, CS | D, CS, PS | Monni et al., 2004 |
| 1 Data are given as upper and lower bounds of the 95 percent confidence interval, and expressed as percent relative to the mean 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). |  |  |  |  |  |

* * *

TABLE 2.14
CH N2

$$
\\mathrm {C H} \_ {4}
$$

$$
\\mathrm {N} \_ {2} \\mathrm {O}
$$

\| TABLE 2.14

| SUMMARY OF UNCERTAINTY ASSESSMENT OF CH4 AND N2O EMISSION FACTORS FOR STATIONARY COMBUSTION SOURCES OF SELECTED COUNTRIES |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- |
| Country | 95% confidence interval1 | Distribution | 2003 GHG inventory submission2 |  | References |
| Approach3 | Emission factor4 |  |  |  |  |
| CH4 |  |  |  |  |  |
| Austria | $\\pm$ 50 | Normal | C, CS | CS | Winiwarter and Rypdal, 2001 |
| Finland | -75 to +10 | β | T1,T2,CS | CS,PS | Monni et al., 2004 |
| Norway | -50 to +100 | Lognormal | T2,CS | D,CS,PS | Rypdal, 1999 |
| The Netherlands | $\\pm$ 25 | - | T2,CS | CS,PS | Van Amstel et al., 2000 |
| UK | $\\pm$ 50 | Truncated normal | T2 | D,C,CS | Baggott et al., 2005 |
| USA | Order of magnitude | - | T1 | D,CS | EIA, 1999 |
| N2O |  |  |  |  |  |
| Austria | $\\pm$ 20 | Normal | C,CS | CS | Winiwarter and Rypdal, 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 | $\\pm$ 75 | - | T1,CS | D,PS | Van Amstel et al., 2000 |
| UK | $\\pm$ 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 the mean value |  |  |  |  |  |

$$
\\mathrm {C H} \_ {4}
$$

1
Data are given as upper and lower bounds of the 95 percent confidence interval, and expressed as percent relative to the
mean value.
2
The information in the columns is based on the 2003 National Greenhouse Gas Inventory submissions from Annex I

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),

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-

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 these
circumstances, overall systematic errors are likely to be small. Experts believe that the uncertainty resulting from
the two errors combined is probably in the range of ±5 percent for most developed countries. For countries with

4
Notation keys that specify the emission factor used: D (IPCC default), C (CORINAIR), CS (Country-specific), PS (Plant-
Specific).

2.4.2 Activity data uncertainties 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

| TABLE2.15LEVEL OF UNCERTAINTY ASSOCIATED WITH STATIONARY COMBUSTION ACTIVITY DATA |  |  |  |  |
| --- | --- | --- | --- | --- |
| Sector | Well developed statistical systems |  | Less 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:IPCCGood Practice Guidance和Uncertainty Management in National Greenhouse Gas Inventories(2000) |  |  |  |  |

2.5 INVENTORY QUALITY ASSURANCE/QUALITY
CONTROL QA/QC

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 such
that 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 the

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 these
references, particularly if they describe new methodological developments or emission factors for particular
technologies or national circumstances. For all country- and technology-specific emission factors, it is good
practice to provide the date of the last revision and any verification of the accuracy.

$$
\\mathrm {C O} \_ {2}
$$

$$
\\mathrm {n o n - C O} \_ {2}
$$

* * *

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 in
for 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

| TABLE 2.16LIST OF SOURCE CATEGORIES FOR STATIONARY COMBUSTION |  |
| --- | --- |
| Code | 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 |

* * *

QA/QC PROCEDURES FOR STATIONARY SOURCES

| TABLE 217QA/QC PROCEDURES FOR STATIONARY SOURCES |  |  |
| --- | --- | --- |
| Activity | Calculations of CO2 emissions from stationary combustion | Calculations of non-CO2 emissions from stationary combustion |
| Comparison of emission estimates using different approaches | The inventory compiler should compare estimates of CO2 emissions from fuel combustion prepared using the Sectoral Approach with the Reference Approach, and account for any difference greater than or equal 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. | If a Tier 2 approach with country-specific factors is used, the inventory compiler should compare the result to emissions calculated using the Tier 1 approach with default IPCC factors. This type of comparison may require aggregating Tier 2 emissions to the same sector and fuel groupings as the Tier 1 approach. The approach should be documented and any discrepancies investigated. |
| If possible, the inventory investigator should compare the consistency of the calculations in relation to the maximum carbon content of fuels that are combusted by stationary sources. Anticipated carbon balances should be maintained throughout the combustion sectors. |  |  |
| Activity data check | The national agency in charge of energy statistics should construct, if resources permit, national commodity balances expressed in mass units, and construct mass balances of fuel conversion industries. The time series of statistical differences should be checked for systematic effects (indicated by the differences 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 energy balances 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 or exported 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, the inventory 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. |  |  |

* * *

Volume 2: Energy

QA/QC PROCEDURES FOR STATIONARY SOURCES

| Activity | Calculations of CO2 emissions from stationary combustion | Calculations of non-CO2 emissions from stationary combustion |
| --- | --- | --- |
| Emission factors check and 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 incorrect carbon content.Monitoring systems at large combustion plants may be used to check the emission 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. | If country-specific emission factors are used,the inventory compiler should compare them to the IPCC defaults,and explain and document differences.The inventory compiler should compare the emission factors used with site or plant level factors,if these are available.This type of comparison provides an indication of how reasonable and representative the national factor is. |
| Evaluation of direct measurements | The inventory compiler should evaluate the quality control associated with 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 and analysis used to derive the factor,continued use of the factor may be questioned. | If direct measurements are used,the inventory compiler should ensure that they are made according to good measurement practices including appropriate QA/QC procedures.Direct measurements should be compared to the results derived from using IPCC default factors. |
| CO2 capture | 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 amount injected to storage. | Not applicable |
| External review | 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. |  |

* * *

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$$
\\mathrm {C O} \_ {2}
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$$
\\left(\\mathrm {C H} \_ {4}\\right)
$$

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