Commission Implementing Regulation (EU) 2025/2547 of 10 December 2025 laying down rules for the application of Regulation (EU) 2023/956 of the European Parliament and the Council as regards the methods for the calculation of emissions embedded in goods

Where the continuous measurement equipment for a parameter is out of control, out of range or out of operation for part of the hour or reference period, the related hourly average shall be calculated pro rata to the remaining data points for that specific hour or shorter reference period, provided that at least 80 % of the maximum number of data points for a parameter are available.

Where fewer than 80 % of the maximum number of data points for a parameter are available, the following methods shall be used.

In the case of a parameter directly measured as concentration, a substitution value as the sum of an average concentration and twice the standard deviation associated with that average is used, applying the following equation:

Image omitted; see official source	(Equation 19)

Where:

Image omitted; see official source is the arithmetic mean of the concentration of the specific parameter over the whole reporting period or, where specific circumstances applied when data loss occurred, an appropriate period reflecting the specific circumstances and

σ c is the best estimate of the standard deviation of the concentration of the specific parameter over the whole reporting or, where specific circumstances applied when data loss occurred, an appropriate period reflecting the specific circumstances.

Where the reporting period is not applicable for determining such substitution values due to significant technical changes at the installation, another sufficiently representative timeframe shall be chosen for determining the average and standard deviation, where possible of a duration of at least six months.

In the case of a parameter other than concentration, substitute values shall be determined through a suitable mass balance model or an energy balance of the process. This model shall be validated by using the remaining measured parameters of the measurement-based methodology and data at regular working conditions, considering a time period of the same duration as the data gap.

B.6.3.   Quality requirements

All measurements shall be carried out applying methods based on:

• — ISO 20181:2023 Stationary source emissions – Quality assurance of automated measuring systems;

• — ISO 14164:1999 Stationary source emissions – Determination of the volume flowrate of gas streams in ducts – Automated method;

• — other relevant ISO standards, in particular ISO 16911-2 (Stationary source emissions – Manual and automatic determination of velocity and volume flow rate in ducts).

Where no applicable published standards exist, suitable draft standards, industry best practice guidelines or other scientifically proven methodologies shall be used, limiting sampling and measurement bias.

All relevant aspects of the continuous measurement system shall be considered, including the location of the equipment, calibration, measurement, quality assurance and quality control.

Laboratories carrying out measurements, calibrations and relevant equipment assessments for continuous measurement systems shall be accredited in accordance with ISO/IEC 17025 for the relevant analytical methods or calibration activities. Where the laboratory does not have such accreditation, sufficient competence in line with point B.5.4.3 shall be ensured.

B.6.4.   Corroborating calculations

CO2 emissions determined by a measurement-based methodology shall be corroborated by calculating the annual emissions of each greenhouse gas in question for the same emission sources and source streams. For this purpose, the requirements laid down in points B.4 to B.6 may be simplified as appropriate.

B.6.5.   Minimum requirements for continuous emissions measurements

As a minimum requirement, an uncertainty 7,5 % of the GHG emissions of an emission source over the full reporting period shall be achieved. For minor emission sources, or under exceptional circumstances 10 % uncertainty may be allowed. It is a recommended improvement to achieve an uncertainty of 2,5 % at least for emission sources emitting more than 100 000 tonnes of fossil CO2e per reporting period.

B.7.   Requirements for determining perfluorocarbon emissions

Monitoring shall cover emissions of perfluorocarbons (PFCs) resulting from anode effects including fugitive emissions of perfluorocarbons. Emissions not related to anode effects shall be determined based on estimation methods in accordance with industry best practice, in particular guidelines provided by the International Aluminium Institute.

PFC emissions shall be calculated from the emissions measurable in a duct or stack (‘point source emissions’) as well as fugitive emissions using the collection efficiency of the duct:

PFC emissions (total) = PFC emissions (duct)/collection efficiency	(Equation 20)

The collection efficiency shall be measured when the installation-specific emission factors are determined.

The emissions of CF4 and C2F6 emitted through a duct or stack shall be calculated by using one of the following methods:

• — method A where the anode effect minutes per cell-day are recorded;

• — method B where the anode effect overvoltage is recorded.

B.7.1.   Calculation Method A – Slope Method

The following equations for determining PFC emissions shall be used:

CF4 emissions [t] = AEM × (SEFCF4/1 000) × PrAl	(Equation 21)
C2F6 emissions [t] = CF4 emissions × FC2 F6	(Equation 22)

Where:

AEM is the anode effect minutes/cell-day;

SEFCF4 is the slope emission factor expressed in (kg CF4/t Al produced)/(anode effect minutes/cell-day)]. Where different cell-types are used, different SEF may be applied as appropriate;

PrAl is the production of primary aluminium [t] during the reporting period; and

FC2 F6 is the weight fraction of C2F6 [t C2F6/t CF4].

The anode effect minutes per cell-day expresses the frequency of anode effects (number anode effects/cell-day) multiplied by the average duration of anode effects (anode effect minutes/occurrence):

AEM = frequency × average duration	(Equation 23)

Emission factor: The emission factor for CF4 (slope emission factor, SEFCF4) expresses the amount [kg] of CF4 emitted per tonne of aluminium produced per anode effect minute per cell-day. The emission factor (weight fraction FC2 F6) of C2F6 expresses the amount [kg] of C2F6 emitted proportionate to the amount [kg] of CF4 emitted.

Minimum requirement: Technology-specific emission factors from Table 2 of this point are used.

Recommended improvement: Installation-specific emission factors for CF4 and C2F6 are established through continuous or intermittent field measurements. For the determination of those emission factors industry best practice shall be applied, in particular the most recent guidelines provided by the International Aluminium Institute. The emission factor shall also take into account emissions related to non-anode effects. Each emission factor shall be determined with a maximum uncertainty of ± 15 %. The emission factors shall be determined at least every three years or earlier where necessary due to relevant changes at the installation. Relevant changes shall include a change in the distribution of anode effect duration, or a change in the control algorithm affecting the mix of the types of anode effects or the nature of the anode effect termination routine.

Table 2

Technology-specific emission factors related to activity data for the slope method

Technology	Emission factor for CF4 (SEFCF4) [(kg CF4/t Al)/(AE-Mins/cell-day)]	Emission factor for C2F6 (FC2 F6) [t C2F6/t CF4]
Legacy Point Feed Pre Bake (PFPB L)	0,122	0,097
Modern Point Feed Pre Bake (PFPB M)	0,104	0,057
Modern Point-Fed Prebake without fully automated anode effect intervention strategies for PFC emissions (PFPB MW)	–10	–10
Centre Worked Prebake (CWPB)	0,143	0,121
Side Worked Prebake (SWPB)	0,233	0,280
Vertical Stud Søderberg (VSS)	0,058	0,086
Horizontal Stud Søderberg (HSS)	0,165	0,077

B.7.2.   Calculation Method B – Overvoltage Method

For the overvoltage method, the following equations shall be used:

CF4 emissions [t] = OVC × (AEO/CE) × PrAl × 0,001	(Equation 24)
C2F6 emissions [t] = CF4 emissions × FC2 F6	(Equation 25)

Where:

OVC is the overvoltage coefficient (‘emission factor’) expressed in kg CF4 per tonne of aluminium produced per mV overvoltage;

AEO is the anode effect overvoltage per cell [mV] determined as the integral of (time × voltage above the target voltage) divided by the time (duration) of data collection;

CE is the average current efficiency of aluminium production [%];

PrAl is the annual production of primary aluminium [t]; and

FC2 F6 is the weight fraction of C2F6 [t C2F6/t CF4].

the term AEO/CE (Anode effect overvoltage / current efficiency) expresses the time-integrated average anode effect overvoltage [mV overvoltage] per average current efficiency [%].

Minimum requirement: Technology-specific emission factors from Table 3 of this Annex shall be used.

Recommended improvement: Installation-specific emission factors are used for CF4 [(kg CF4/t Al)/(mV)] and C2F6 [t C2F6/t CF4] established through continuous or intermittent field measurements. For the determination of those emission factors industry best practice shall be applied, in particular the most recent guidelines provided by the International Aluminium Institute. The emission factors shall be determined with a maximum uncertainty of ± 15 % each. The emission factors shall be determined at least every three years or earlier where necessary due to relevant changes at the installation. Relevant changes shall include a change in the distribution of anode effect duration, or a change in the control algorithm affecting the mix of the types of anode effects or the nature of the anode effect termination routine

Table 3

Technology-specific emission factors related to overvoltage activity data

Technology	Emission factor for CF4 [(kg CF4/t Al)/mV]	Emission factor for C2F6 [t C2F6/t CF4]
Centre Worked Prebake (CWPB)	1,16	0,121
Side Worked Prebake (SWPB)	3,65	0,252

B.7.3.   Determination of CO2e emissions

CO2e emissions shall be calculated from CF4 and C2F6 emissions as follows, using the global warming potentials listed in point G of this Annex.

PFC emissions [t CO2e] = CF4 emissions [t] × GWPCF4 + C2F6 emissions [t] × GWPC2 F6	(Equation 26)

B.8.   Requirements for CO2 transfers

B.8.1.   *CO2 contained in gases (‘inherent CO2

’)*

Inherent CO2 that is transferred into an installation, including that contained in natural gas, a waste gas (including blast furnace or coke oven gas) or in process inputs (including synthesis gas), shall be included in the emission factor for that source stream.

Where inherent CO2 transferred out is emitted (e.g. vented or flared), it shall be counted as emissions of the installation where it originates.

B.8.2.   Eligibility to deduct stored or used CO2

	(1)	In the following cases CO2 originating from fossil carbon and originating from combustion or processes leading to process emissions, or which is imported from other installations, including in the form of inherent CO2, may be accounted for as not emitted, provided they comply with point (2): (a) if the CO2 is used within the installation or transferred out of the installation to any of the following: — an installation for the purpose of CO2 capture which monitors emissions for the purpose of this Regulation; — an installation or transport network with the purpose of long-term geological storage of CO2 which monitors emissions for the purpose of this Regulation; — a storage site for the purpose of long-term geological storage which monitors emissions for the purpose of this Regulation, providing for conditions equivalent to those laid out in Union law. (b) if the CO2 is used within the installation or transferred out of the installation to an entity which monitors emissions for the purpose of this Regulation, in order to produce products in which the carbon stemming from CO2 is permanently chemically bound so that it does not enter the atmosphere under normal use, including any normal activity taking place after the end of the life of the product, as defined in Commission Delegated Regulation (EU) 2024/2620 11.
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	(2)	CO2 transferred to another installation for the purposes referred to in point (1) may be accounted for as not emitted only to the extent evidence is provided across the whole chain of custody to the storage site or installation of CO2 use and including any transport operators, of the fraction of CO2 actually stored or used for the production of chemically stable products compared to the total amount of CO2 transferred out of the originating installation. In addition, installation operators shall comply with the monitoring rules set in point B.8.3.

B.8.3.   Monitoring rules for CO2 transfers

The identity and contact data of a responsible person of the receiving installations or entities shall be clearly laid down in the monitoring plan. The amount of CO2 considered not emitted shall be reported in the emission report pursuant to Annex IV.

The identity and contact data of a responsible person of the installations or entities from which CO2 was received shall be clearly laid down in the monitoring plan. The amount of CO2 received shall be reported in the emission report pursuant to Annex IV.

For the determination of the quantity of CO2 transferred from one installation to another, a measurement-based methodology shall be used.

For the amount of CO2 permanently chemically bound in products, a calculation-based methodology shall be used, preferably using a mass balance. The chemical reactions applied, and all relevant stoichiometric factors shall be laid down in the monitoring plan.

If CO2 is used for the purposes referred to in point (1) of point B.8.2., the monitoring methods set out in points 21 to 23 of Annex IV to Commission Implementing Regulation (EU) 2018/2066 ¹² shall be applied.

B.9.   Sector-specific requirements

B.9.1.   Additional rules for combustion units

Combustion emissions shall cover all CO2 emissions from the combustion of carbon-containing fuels, including wastes, independent of any other classification of such emissions or fuels. Where it is unclear if a material acts as fuel or as process input, e.g., for reducing metal ores, that material’s emissions shall be monitored the same way as combustion emissions. All stationary combustion units shall be considered, including boilers, burners, turbines, heaters, furnaces, incinerators, calciners, kilns, ovens, dryers, engines, fuel cells, chemical looping combustion units, flares, thermal or catalytic post-combustion units.

Monitoring shall furthermore include CO2 process emissions from flue gas scrubbing, in particular CO2 from limestone or other carbonates for desulphurisation and similar scrubbing, and from urea used in de-NOx units.

B.9.1.1.   Desulphurisation and other acid gas scrubbing

Process CO2 emissions from the use of carbonates for acid gas scrubbing from the flue gas stream shall be calculated on the basis of carbonate consumed (Method A). In the case of desulphurisation, calculation may be based alternatively on the quantity of gypsum produced (Method B). In the latter case, the emission factor shall be the stoichiometric ratio of dry gypsum (CaSO4 × 2H2O) to CO2 emitted: 0,2558 t CO2/t gypsum.

B.9.1.2.   De-NOx

If urea is used as reduction agent in a de-NOx unit, process CO2 emissions from its use shall be calculated using method A, applying an emission factor based on the stoichiometric ratio of 0,7328 t CO2/t urea.

B.9.1.3.   Monitoring of flares

When calculating emissions from flares, routine flaring as well as operational flaring (trips, start-up, and shutdown as well as emergency relieves) shall be covered. Inherent CO2 in in the flared gases is to be included.

If more accurate monitoring is technically not feasible or would lead to unreasonable costs, a reference emission factor of 0,00393 t CO2/Nm³ shall be used, derived from the combustion of pure ethane used as a conservative proxy for flare gases.

It is a recommended improvement to determine installation-specific emission factors derived from an estimate of the molecular weight of the flare stream, using process modelling based on industry standard models. By considering the relative proportions and the molecular weights of each of the contributing streams, a weighted annual average figure shall be derived for the molecular weight of the flare gas.

For activity data, higher measurement uncertainty than for other fuels combusted is acceptable.

B.9.2.   Additional rules for emissions from cement clinker production

B.9.2.1.   Additional rules for Method A (input based)

Where method A (kiln input based) is used for determining process emissions, the following special rules shall apply:

• — Where cement kiln dust (CKD) or bypass dust leave the kiln system, the related quantities of raw material shall not be considered as process input. Emissions from CKD shall be calculated separately in accordance with point B.9.2.3.

• — Either raw meal as a whole, or separate input materials may be characterised, avoiding double counting or omissions from returned or by-passed materials. Where activity data is determined based on the clinker produced, the net amount of raw meal may be determined by means of a site-specific empirical raw meal/clinker ratio. That ratio shall be updated at least once per year applying industry best practice guidelines.

B.9.2.2.   Additional rules for Method B (output based)

Where method B (clinker output based) is used for determining process emissions, the following special rules shall apply:

Activity data shall be determined as the clinker production [t] over the reporting period in one of the following ways:

• — by direct weighing of clinker;

• — based on cement deliveries, by material balance taking into account dispatch of clinker, clinker supplies as well as clinker stock variation, using the following formula:

Image omitted; see official source	(Equation 27)

Where:

Cliprod is the amount of clinker produced expressed in tonnes;

Cemdeliv is the amount of cement deliveries expressed in tonnes;

CemSV are the cement stock variations expressed in tonnes;

CCR is the clinker to cement ratio (tonnes clinker per tonne cement);

Clis is the amount of clinker supplied expressed in tonnes;

Clid is the amount of clinker dispatched expressed in tonnes; and

CliSV is the amount of clinker stock variations expressed in tonnes.

The clinker to cement ratio shall either be derived separately for each of the different cement products based on laboratory analyses in line with the provisions of point B.5.4 or calculated as ratio from the difference of cement deliveries and stock changes and all materials used as additives to the cement including by-pass dust and cement kiln dust.

As minimum requirement to determine the emission factor, a standard value of 0,525 t CO2/t clinker shall be applied.

B.9.2.3.   Emissions related to discarded dust

CO2 process emissions from bypass dust or cement kiln dust (CKD) leaving the kiln system, shall be added to the emissions, corrected for a partial calcination ratio of CKD.

Minimum requirement: An emission factor of 0,525 t CO2/t dust shall be applied.

Recommended improvement: The emission factor (EF) is determined at least once annually in line with the provisions of point B.5.4 and using the following formula:

Image omitted; see official source	(Equation 28)

Where:

EFCKD is the emission factor of partially calcined cement kiln dust [t CO2/t CKD];

EFCli is the installation-specific emission factor of clinker [t CO2/t clinker]; and

d is the degree of CKD calcination (released CO2 as % of total carbonate CO2 in the raw mix).

B.9.3.   Additional rules for emissions from nitric acid production

B.9.3.1.   General rules for N2O measurement

N2O emissions shall be determined using a measurement-based methodology. N2O concentrations in the flue gas from each emission source shall be measured at a representative point, after the NOx/N2O abatement equipment, where abatement is used. Techniques capable of measuring N2O concentrations of all emission sources during both abated and unabated conditions shall be applied. All measurements shall be adjusted to a dry gas basis where required and consistently reported.

B.9.3.2.   Determination of flue gas flow

For monitoring flue gas flow, the mass balance method set out in point B.6.2.5 shall be used, unless it is technically not feasible. In that case, an alternative method may be used, including by another mass balance method based on significant parameters such as ammonia input load, or determination of flow by continuous emissions flow measurement.

The flue gas flow shall be calculated in accordance with the following formula:

Vflue gas flow [Nm3/h] = Vair × (1 – O2,air)/(1 – O2,flue gas)	(Equation 29)

Where:

Vair is the total input air flow in Nm³/h at standard conditions;

O2,air is the volume fraction of O2 in dry air (= 0,2095); and

O2,flue gas is the volume fraction of O2 in the flue gas.

Vair shall be calculated as the sum of all air flows entering the nitric acid production unit, in particular primary and secondary input air, and seal input air, where applicable.

All measurements shall be adjusted to a dry gas basis and reported consistently.

B.9.3.3.   Oxygen (O2) concentrations

Where necessary for calculating the flue gas flow in accordance with point B.9.3.2, the oxygen concentrations in the flue gas shall be measured, applying the requirements laid down in point B.6.2.2. All measurements shall be adjusted to a dry gas basis and reported consistently.

C. HEAT FLOWS

C.1.   Rules for determining net measurable heat

C.1.1.   Principles

All specified amounts of measurable heat shall always refer to net amount of measurable heat, determined as the heat content (enthalpy) of the heat flow transmitted to the heat-consuming process or external user minus the heat content of the return flow.

Heat-consuming processes necessary for operating the heat production and distribution, such as deaerators, make-up water preparation, and regular blow offs, shall be taken into account in the efficiency of the heat system and shall be accounted for in the embedded emissions of goods.

Where the same heat medium is used by several consecutive processes and its heat is consumed starting from different temperature levels, the quantity of heat consumed by each heat-consuming process shall be determined separately, unless the processes are part of the overall production process of the same goods. Re-heating of the transfer medium between consecutive heat-consuming processes shall be treated like additional heat production.

Where heat is used to provide cooling via an absorption cooling process, that cooling process shall be considered as the heat-consuming process.

C.1.2.   Methodology for determining net amounts of measurable heat

For the purpose of selecting data sources for quantification of energy flows in accordance with Article 4, the following methods for determining net amounts of measurable heat shall be considered:

C.1.2.1.   Method 1: Using measurements

Under this method, all relevant parameters shall be measured, in particular temperature, pressure, state of the transmitted as well as the returned heat medium. In the case of steam, the state of the medium shall refer to its saturation or degree of superheating. The (volumetric) flow rate of the heat transfer medium shall be measured. Based on the measured values, the enthalpy and the specific volume of the heat transfer medium shall be determined using suitable steam tables or engineering software.

The mass flow rate of the medium shall be calculated as:

Image omitted; see official source	(Equation 30)

Where:

Image omitted; see official source is the mass flow rate in kg/s;

Image omitted; see official source is the volumetric flow rate in m³/s; and

v is the specific volume in m³/kg.

As the mass flow rate is considered the same for transmitted and returned medium, the heat flow rate shall be calculated using the difference in enthalpy between the transmitted flow and the return, as follows:

Image omitted; see official source	(Equation 31)

Where:

Image omitted; see official source is the heat flow rate in kJ/s;

hflow is the specific enthalpy of the transmitted flow in kJ/kg;

hreturn is the specific enthalpy of the return flow in kJ/kg; and

Image omitted; see official source is the mass flow rate in kg/s.

In the case of steam or hot water used as heat transfer medium, where the condensate is not returned, or where it is not feasible to estimate the enthalpy of the returned condensate, hreturn shall be determined based on a temperature of 90 °C.

If the mass flow rates are known to be not identical, the following shall apply:

• — where evidence is available that condensate remains in the product (e.g. in ‘life steam injection’ processes), the respective amount of condensate enthalpy is not deducted;

• — where heat transfer medium is known to be lost (e.g. due to leakages or sewering), an estimate for the respective mass flow is deducted from the mass flow of the transmitted heat transfer medium.

For determining the annual net heat flow from the above data, one of the following methods shall be used, subject to the measurement equipment and data processing available:

• — determine annual average values for the parameters determining the annual average enthalpy of the transmitted and returned heat medium, multiplied by the total annual mass flow, using Equation 31;

• — determine hourly values of the heat flow and sum up those values over the annual total operating time of the heat system. Subject to the data processing system, hourly values may be substituted by other time intervals as appropriate.

C.1.2.2.   Method 2: Calculation of a proxy based on measured efficiency

The amounts of net measurable heat shall be determined based on the fuel input and the measured efficiency related to the heat production and transmission:

Image omitted; see official source	(Equation 32)
Image omitted; see official source	(Equation 33)

Where:

Q is the amount of heat expressed in TJ;

ηH is the measured efficiency of heat production and transmission;

EIn is the energy input from fuels;

ADi are the annual activity data (i.e. quantities consumed) of the fuels i; and

NCVi are the net calorific values of the fuels i.

The value of ηH is either measured over a reasonably long period, which sufficiently takes into account different load states of the installation or taken from the manufacturer's documentation. In that regard the specific part load curve shall be taken into account by using an annual load factor, as follows:

Image omitted; see official source	(Equation 34)

Where:

LF is the load factor;

EIn the energy input as determined using Equation 33 over the reporting period; and

EMax the maximum fuel input if the heat producing unit had been running at 100 % nominal load for the full calendar year.

The efficiency shall be based on a situation in which all condensate is returned. A temperature of 90 °C shall be assumed for the returned condensate.

C.1.2.3.   Method 3: Calculating a proxy based on the reference efficiency

This method is identical to method 3, but using a reference efficiency of 70 % (ηRef,H = 0,7) in Equation 32.

C.1.3.   Special rules

Where an installation consumes measurable heat produced from exothermic chemical processes other than combustion, such as in ammonia or nitric acid production, that amount of heat consumed shall be determined separately from other measurable heat and that heat consumption shall be assigned zero CO2e emissions.

D. ELECTRICITY

D.1.   Calculation of the emissions related to electricity

The emissions relating to electricity production or consumption shall be calculated using the following equation:

Image omitted; see official source	(Equation 35)

Where:

Em el are the emissions related to electricity produced or consumed, expressed in t CO2;

E el is the electricity produced or consumed expressed in MWh; and

EF el is the emission factor for electricity applied, expressed in t CO2/MWh.

D.2.   Rules for determining the emission factor of electricity imported into the customs territory of the Union

For determining the specific embedded emissions of electricity imported into the customs territory of the Union, only direct emissions shall be applicable in accordance with point 2 of Annex IV to Regulation (EU) 2023/956.

The emission factor for calculating the specific embedded emissions of electricity shall be established as follows:

• — the specific default value for a third country, group of third countries or region within a third country, as the relevant CO2 emission factor as set out in point D.2.1 shall be used;

• — where no specific default value is available pursuant to point (a), the CO2 emission factor in the EU as set out in point D.2.2 be used;

• — where a country, or group of third countries, submits sufficient evidence based on official and public information to demonstrate that the CO2 emission factor in the third country, group of third countries or region within a third country from where electricity is imported is lower than the values in accordance with points (a) and (b), and where the conditions provided in point D.2.3 are fulfilled, the alternative default value determined on the basis of the available and reliable data provided will be used;

• — an authorised CBAM declarant may apply actual embedded emissions instead of default values for the calculation of embedded emissions of the imported electricity, if it can be demonstrated, through the elements of evidence outlined in point D.2.4 of this Annex, that the cumulative criteria (a) to (d) provided in point 5 of Annex IV to Regulation (EU) 2023/956 are met, and the calculation is based on data determined in accordance with this Annex by the producer of the electricity, calculated using point D.4.1 or D.4.2 of this Annex.

D.2.1.   CO2 emission factor based on specific default values

In accordance with point 4.2.1 of Annex IV to Regulation (EU) 2023/956, CO2 emission factors in the third country, group of third countries or region within a third country, shall be used, based on the best data available to the

D.2.2.   CO2 emission factor of the EU

Pursuant to point 4.2.2 of Annex IV to Regulation (EU) 2023/956, the CO2 emission factor for the Union shall apply.

D.2.3.   CO2 emission factor based on alternative reliable data

For the purpose of point (c) of point D.2, alternative default values may be used for electricity imported from a given third country during a given year, where a third country or group of third countries provides the Commission, by 30 June of that year, with the datasets from reliable alternative official sources, including national statistics, demonstrating that the CO2 emission factor calculated on the basis of equations 36 and 37 is lower than the CO2 emission factor laid down in accordance with Annex IV of Regulation (EU) 2023/956. Where the Commission considers the provided alternative official sources reliable, it shall amend, where feasible by 30 June of the following year, the relevant default values. The modified default values shall be applicable to electricity imported during the year in whichthe datasets from alternative official sources were provided.

Where a third country or group of third countries provides the datasets from alternative official sources after 30 June of a given year, and where the Commission considers them reliable, it shall amend, where feasible by 30 June of the second year following the year during which the datasets from alternative official sources were provided, the relevant default values. The modified default values shall be applicable to electricity imported during the year following the year in whichthe datasets from alternative official sources were provided. Where the Commission manages to amend the relevant default values in the year following the year during which the datasets from alternative official sources were provided and before the deadline for submitting CBAM declarations in accordance with Article 6 of Regulation (EU) 2023/956, the modified default values shall be applicable to electricity imported during the year in whichthe datasets from alternative official sources were provided.

The alternative CO2 emission factor shall be calculated on the basis of the average of the yearly CO2 emission factors for the most recent five-years period for which reliable data is available.

For this purpose, the yearly CO2 emission factors shall be calculated , based on the following equation:

Image omitted; see official source	(Equation 36)

Where:

Em el,y is the yearly CO2 emission factor for all fossil fuel technologies in the given year in the third country, group of third countries, or region within a third country, capable of exporting electricity to the EU;

E el,y is the total gross electricity generation from all fossil fuel technologies in that year; EF i is the CO2 emission factor for each fossil fuel technology ‘i’; and

E el,i,y is the yearly gross electricity generation for each fossil fuel technology ‘i’.

The CO2 emission factor shall be calculated as a moving average of those years starting with the current year minus two, based on the following equation:

Image omitted; see official source	(Equation 37)

Where:

Em el is the CO2 emission factor resulting from the moving average of the yearly CO2 emission factors of the five previous years, starting from the current year, minus two years, until the current year, minus 6 years;

Em el,y is the CO2 emission factor for each year ‘i’;

i is the variable index for the years to consider; and

y is the current year.

Should more recent, reliable data be available, the moving average may start from the current year, minus one year, until the current year, minus five years.

D.2.4.   Elements of evidence for using actual embedded emissions for electricity imported into the Union

Pursuant to point 5 of Annex IV to Regulation (EU) 2023/956, an authorised CBAM declarant may apply actual embedded emissions instead of default values for the calculation of embedded emissions of a given quantity of imported electricity if the cumulative criteria (a) to (d) provided in that point are met.

The following elements of evidence shall be submitted to demonstrate that the criteria required to justify the use of actual emissions are fulfilled pursuant to point 5 of Annex IV to Regulation (EU) 2023/956 are fulfilled.

• — For criterion (a) as laid down in point 5 of Annex IV to Regulation (EU) 2023/956:

• (a) contractual evidence demonstrating the existence of a power purchase agreement (PPA) concluded directly between the authorised CBAM declarant and a producer of electricity located in a third country for the physical delivery of electricity. The PPA shall be applicable at the time of electricity import for which actual emissions are claimed and shall cover at least the amount of electricity for which actual emissions are claimed. Where the PPA was concluded through an intermediary, the contractual evidence shall demonstrate that only one single contract was concluded between the three contracting parties.

• — For criterion (b) as laid down in point 5 of Annex IV to Regulation (EU) 2023/956, one of the following:

• (a) a single line diagram demonstrating the existence of a direct connection between the installation producing electricity and the Union transmission system;

• (b) written documentation, either from the transmission system operator or from another entity with access to relevant information, attesting that at the time of export, determined on an hourly basis, there was no physical network congestion at any point in the network between the installation and the Union transmission system.

• — For criterion (c) as laid down in point 5 of Annex IV to Regulation (EU) 2023/956:

• (a) data showing that the installation producing electricity does not emit more than 550 grammes of CO2 of fossil fuel origin per kilowatt-hour of electricity.

• — For criterion (d) as laid down in point 5 of Annex IV to Regulation (EU) 2023/956:

• (a) written documentation, either from the person who nominated the relevant capacity at the interconnector or from the relevant transmission system operator, demonstrating that a given quantity of electricity has been nominated in the country of origin, the country of destination and, if relevant, each country of transit, and demonstrating the period of time to which the nomination of capacity refers; and

• (b) data from a smart metering system demonstrating that the production of a corresponding amount of electricity by the installation occurred within the same measurement period as the nomination of the capacity. This period shall not exceed one hour.

• — For criteria (e) as laid down in point 5 of Annex IV to Regulation (EU) 2023/956:

• (a) monthly interim reports containing the elements of evidence laid down in this point demonstrating how criteria (a) to (d) as laid down in point 5 of Annex IV to Regulation (EU) 2023/956 are fulfilled.

D.3.   Rules for determining electricity quantities used for the production of goods other than electricity

For the purpose of determining embedded emissions, metering of electricity quantities shall apply to real power, not apparent power (complex power). Only the active power component shall be metered, and the reactive power shall be disregarded.

For the production of electricity, the activity level shall refer to net electricity leaving the system boundaries of the power plant or cogeneration unit, after subtraction of internally consumed electricity.

D.4.   Rules for determining the embedded indirect emissions of electricity used for the production of goods other than electricity

Emission factors for electricity shall be determined based on either:

• — the average emission factor of the country of origin electricity grid, made available in accordance with Annex IV of Regulation (EU) 2023/956; or

• — where sufficient evidence is submitted based on official and public information to demonstrate that the average emission factor of the grid of a third country or group of third countries, in which electricity was produced, is lower than the values established in accordance with point (a), an alternative default value shall be established in accordance with point D.4.4;

• — actual emission factors for electricity may be used in accordance with points D.4.1 to D.4.3.

D.4.1.   Emission factor of electricity produced by methods other than cogeneration

Where the criteria for the use of actual emissions for electricity or indirect emissions, as laid down in Annex IV to Regulation (EU) 2023/956, are met, for electricity produced from the combustion of fuels, except electricity produced by cogeneration, the emission factor of electricity EFEl shall be determined based on the relevant fuel mix and the emissions attributable to the electricity production shall be calculated as:

EFEl = (Σ ADi × NCVi × EFi + EmFGC)/ElprodIs	(Equation 38)

Where:

ADi are the annual activity data (i.e. quantities consumed) of the fuels i used for the electricity production expressed in tonnes or Nm³;

NCVi are the net calorific values of the fuels i expressed in TJ/t or TJ/Nm³;

EFi is the emission factors of the fuels i expressed in t CO2/TJ;

EmFGC are the process emissions from flue gas cleaning expressed in t CO2; and

Elprod is the net amount of electricity produced expressed in MWh. It may include quantities of electricity produced from sources other than combustion of fuels.

Where a waste gas is part of the fuel mix used, and where the emission factor of the waste gas is higher than the standard emission factor of natural gas given in Table 1 of point G, that standard emission factor shall be used to calculate EFEl instead of the emission factor of the waste gas.

D.4.2.   Emission factor of electricity produced by cogeneration

Where the criteria for the use of actual emissions for indirect emissions, as laid down in Annex IV to Regulation (EU) 2023/956, are met, the emission factor of electricity production by cogeneration shall be determined accrding to point A.2.2 of Annex III .

D.4.3.   Elements of evidence for using actual indirect embedded emission

Pursuant to point 6 of Annex IV to Regulation (EU) 2023/956, an authorised CBAM declarant may apply actual embedded emissions instead of default values for the calculation of embedded indirect emissions if the required criteria are met. Where the criteria are met, the emission factor shall be determined in accordance with points D.4.1 or D.4.2 of this Annex.

The following elements of evidence shall be provided to demonstrate that the criteria required to justify the use of actual embedded emissions for indirect emissions pursuant to point 6 of Annex IV to Regulation (EU) 2023/956 are fulfilled.

• — For the demonstration of a direct technical link:

• (a) single line diagram demonstrating the existence of a direct technical link between the installation in which the imported good is produced and the electricity generation source;

• (b) data from a smart metering system demonstrating that the amount of electricity for which the actual emissions are claimed was produced by the installation producing electricity connected by the direct technical link, and demonstrating the time during which the electricity production occurred, with reference to measurements periods not exceeding an hour;

• (c) data from a smart metering system demonstrating that the amount of electricity for which the actual emissions are claimed, was delivered, within the same measurement period not exceeding one hour, to an installation connected by the direct technical link and producing a good listed in Annex I of Regulation (EU) 2023/956;

• (d) where the direct technical link connects multiple installations producing electricity with one or multiple installations producing a good listed in Annex I to Regulation (EU) 2023/956, a contract between the operators of the two installations requiring the delivery of at least the amount of electricity for which the actual emissions are claimed from one installation to the other. Where the electricity production installation and the installation producing a good listed in Annex I to Regulation (EU) 2023/956 are owned by the same legal entity, an intra-company off-take agreement requiring the delivery of at least the corresponding amount of electricity.

• — For the demonstration of a power purchase agreement:

• (a) contractual evidence demonstrating the existence of a PPA concluded directly between an installation producing goods listed in Annex I to Regulation (EU) 2023/956 and a producer of electricity located in a third country for the physical delivery of electricity. Where the PPA was concluded through an intermediary, the contractual evidence shall demonstrate that only one single contract was concluded between the three contracting parties;

• (b) data from a smart metering system demonstrating that a given amount of electricity was produced by the installation producing electricity and demonstrating the period of time of production;

• (c) data from a smart metering system demonstrating that an equivalent amount of electricity was delivered, within the same measurement period which shall not exceed one hour, to the installation producing goods listed in Annex I to Regulation (EU) 2023/956;

• (d) written documentation, either from transmission system operators, public authorities or from other sources of relevant public and reliable information, demonstrating a physical grid connection between the installation producing electricity and the installation producing goods listed in Annex I to Regulation (EU) 2023/956.

D.4.4.   Emission factor based on alternative reliable data

For the purpose of point (2) of point D.4, alternative default values may be used for electricity used in the production of goods imported during a given year, where a third country or group of third countries demonstrates to the Commission, within 30 June of that year, based on datasets from reliable alternative official sources, including national statistics, that the five years average emission intensity for the third country electricity grid thus calculated on the basis of equations 45 and 56 is lower than the one laid down in accordance with Annex IV to Regulation (EU) 2023/956. Where the Commission considers the provided alternative official sources reliable, it shall amend, where feasible by 30 June of the following year, for that third country or group of third countries, the default value of electricity. The modified default value shall be applicable to electricity used in the production of goods imported during the year in whichthe datasets from alternative official sources were provided.

Where a third country or group of third countries provides datasets from alternative official sources after 30 June of a given year, and where the Commission considers them reliable, it shall amend, where feasible by 30 June of the second year following the year during which the datasets from alternative official sources were provided, for that third country or group of third countries, the default value of electricity. The modified default value shall be applicable to electricity used in the production of goods imported during year following the year in whichthe datasets from alternative official sources were provided. Where the Commission manages to amend the relevant default values in the year following the year during which the datasets from alternative official sources were provided and before the deadline for submitting CBAM declarations in accordance with Article 6 of Regulation (EU) 2023/956, the modified default values shall be applicable to electricity used in the production of goods imported during the year in whichthe datasets from alternative official sources were provided.

The emission factor shall be calculated on the basis of the simple average of the emission factor for the most recent five-years period before the reporting for which reliable data is available.

For the purpose of calculating alternative default values, the Commission shall calculate the yearly emission factors and its respective gross electricity generation in the third country or group of third countries based on the following equation:

Image omitted; see official source	(Equation 39)

Where:

Em el,y is the yearly emission factor for all electricity sources in the given year in the third country;

E el,y is the total gross electricity generation from all electricity sources in that year; EF i is the emission factor for each electricity source ‘i’; and

E el,i,y is the yearly gross electricity generation for each electricity source ‘i’.

The Commission shall calculate the emission factor as a moving average of those years starting with the current year minus two, based on the following equation:

Image omitted; see official source	(Equation 40)

Where:

Em el is the emission factor resulting from the moving average of the emission factors of the five year period starting with the current year minus two;

Em el,y is the emission factor for each year ‘i’;

i is the variable index for the years to consider; and

y is the current year.

Should more recent, reliable data be available, the moving average may start from the current year, minus one year, until the current year, minus five years.

E. MONITORING OF PRECURSORS

The quantity of each precursor consumed in each production process shall be determined in order to calculate the total embedded emissions of the complex goods produced in accordance with point B of Annex III.

If the precursors are covered by the same production process in accordance to Article 4(9), only the quantity of additional precursor used and obtained from other installations or from other production processes shall be determined.

The quantity used and emission properties shall be determined separately for each production process from which the precursor is sourced. The methods used for determining the required data shall be laid down in the monitoring plan of the installation, applying the following provisions:

• (1) Where the precursor is produced within the installation, but in a different production process as assigned by applying Article 4, the data sets to be determined shall include:

• (a) specific embedded direct and indirect emissions of the precursor as average over the reporting period, expressed in tonnes CO2e per tonne of precursor;

• (b) quantity of the precursor used in each production process of the installation.

• (2) Where the precursor is obtained from another installation, data sets to be determined shall include:

• (a) the country of origin of the imported goods;

• (b) the installation where it was produced, identified by

• — the unique installation identifier, if available;

• — the applicable United Nations Code for Trade and Transport Location (UN/LOCODE) of the location;

• — a full address and its English transcript; and

• — the geographical coordinates of the installation;

• (c) if the precursor originates in third countries and territories that are not exempted pursuant to point 1 of Annex III to Regulation (EU) 2023/956;

• (d) the production routes used as defined in Annex I;

• (e) the values of applicable specific parameters required for determining the embedded emissions, as listed in point 2 of Annex IV;

• (f) specific embedded direct and indirect emissions of the precursor as average over the most recent available reporting period, expressed in tonnes CO2e per tonne of precursor;

• (g) the start and end date of the reporting period used by the installation from which the precursor was obtained;

• (h) If the precursor originates in third countries and territories that are exempted pursuant to Annex III, point 1 of Regulation (EU) 2023/956, the specific embedded emissions are considered zero;

• (i) quantity of the precursor used in each production process of the installation.

• (3) For each quantity of precursor for which incomplete or inconclusive data under point (2) was received, the applicable default values made available in accordance with Annex IV of Regulation (EU) 2023/956 shall be used.

• (4) When a type of precursor is produced in different production processes, the specific embedded emissions of that precursors will be calculated as a weighted average of those different production processes.

F. MONITORING OF ACTIVITY LEVELS

The activity level of a production process shall be calculated as the total mass of the goods leaving the production process during the reporting period measured in functional units and in tonnes of goods. Where production processes are defined such that also the production of precursors is included, double counting shall be avoided by counting only the final products of the production process.

Only goods which can be sold or directly used as precursor in another production process shall be taken into account. Off-spec products, by-products, waste, and scrap produced in a production process, irrespective of whether they are returned to production processes, delivered to other installations, or disposed of, shall not be included in the determination of the activity level. They shall therefore be assigned zero embedded emissions when entering another production process.

For determining activity levels, the metering requirements laid down in point B.4 apply.

G. STANDARD FACTORS USED IN THE MONITORING OF DIRECT EMISSIONS AT INSTALLATION LEVEL

Fuel emission standard factors related to net calorific values (NCV)

Table 1

Fuel emission factors related to NCV and net calorific values per mass of fuel

Fuel type description	Emission factor (t CO2/TJ)	Net calorific value (TJ/Gg)	Source
Crude oil	73,3	42,3	IPCC 2006 GL
Orimulsion	77,0	27,5	IPCC 2006 GL
Natural gas liquids	64,2	44,2	IPCC 2006 GL
Motor gasoline	69,3	44,3	IPCC 2006 GL
Kerosene (other than jet kerosene)	71,9	43,8	IPCC 2006 GL
Shale oil	73,3	38,1	IPCC 2006 GL
Gas/Diesel oil	74,1	43,0	IPCC 2006 GL
Residual fuel oil	77,4	40,4	IPCC 2006 GL
Liquefied petroleum gases	63,1	47,3	IPCC 2006 GL
Ethane	61,6	46,4	IPCC 2006 GL
Naphtha	73,3	44,5	IPCC 2006 GL
Bitumen	80,7	40,2	IPCC 2006 GL
Lubricants	73,3	40,2	IPCC 2006 GL
Petroleum coke	97,5	32,5	IPCC 2006 GL
Refinery feedstocks	73,3	43,0	IPCC 2006 GL
Refinery gas	57,6	49,5	IPCC 2006 GL
Paraffin waxes	73,3	40,2	IPCC 2006 GL
White spirit and SBP	73,3	40,2	IPCC 2006 GL
Other petroleum products	73,3	40,2	IPCC 2006 GL
Anthracite	98,3	26,7	IPCC 2006 GL
Coking coal	94,6	28,2	IPCC 2006 GL
Other bituminous coal	94,6	25,8	IPCC 2006 GL
Sub-bituminous coal	96,1	18,9	IPCC 2006 GL
Lignite	101,0	11,9	IPCC 2006 GL
Oil shale and tar sands	107,0	8,9	IPCC 2006 GL
Patent fuel	97,5	20,7	IPCC 2006 GL
Coke oven coke and lignite coke	107,0	28,2	IPCC 2006 GL
Gas coke	107,0	28,2	IPCC 2006 GL
Coal tar	80,7	28,0	IPCC 2006 GL
Gas works gas	44,4	38,7	IPCC 2006 GL
Coke oven gas	44,4	38,7	IPCC 2006 GL
Blast furnace gas	260	2,47	IPCC 2006 GL
Oxygen steel furnace gas	182	7,06	IPCC 2006 GL
Natural gas	56,1	48,0	IPCC 2006 GL
Industrial wastes	143	n.a.	IPCC 2006 GL
Waste oils	73,3	40,2	IPCC 2006 GL
Peat	106,0	9,76	IPCC 2006 GL
Waste tyres	85,0 13	n.a.	World Business Council for Sustainable Development – Cement Sustainability Initiative (WBCSD CSI)
Carbon monoxide	155,2 14	10,1	J. Falbe and M. Regitz, Römpp Chemie Lexikon, Stuttgart, 1995
Methane	54,9 15	50,0	J. Falbe and M. Regitz, Römpp Chemie Lexikon, Stuttgart, 1995

Table 2

Fuel emission factors related to NCV and net calorific values per mass of biomass material

Biomass material	Preliminary EF [t CO2/TJ]	NCV [GJ/t]	Source
Wood / Wood waste (air dry16)	112	15,6	IPCC 2006 GL
Sulphite lyes (black liquor)	95,3	11,8	IPCC 2006 GL
Other primary solid biomass	100	11,6	IPCC 2006 GL
Charcoal	112	29,5	IPCC 2006 GL
Biogasoline	70,8	27,0	IPCC 2006 GL
Biodiesels	70,8	37,0	IPCC 2006 GL17
Other liquid biofuels	79,6	27,4	IPCC 2006 GL
Landfill gas18	54,6	50,4	IPCC 2006 GL
Sludge gas19	54,6	50,4	IPCC 2006 GL
Other biogas19	54,6	50,4	IPCC 2006 GL
Municipal waste (biomass fraction)20	100	11,6	IPCC 2006 GL

Emission factors related to process emissions

Table 3

Stoichiometric emission factor for process emissions from carbonate decomposition (Method A)

Carbonate	Emission factor [t CO2/t Carbonate]
CaCO3	0,440
MgCO3	0,522
Na2CO3	0,415
BaCO3	0,223
Li2CO3	0,596
K2CO3	0,318
SrCO3	0,298
NaHCO3	0,524
FeCO3	0,380
General	Emission factor = [M(CO2)]/{Y × [M(x)] + Z × [M(CO3 2 -)]} X = metal M(x) = molecular weight of X in [g/mol] M(CO2) = molecular weight of CO2 in [g/mol] M(CO3 2 -) = molecular weight of CO3 2 - in [g/mol] Y = stoichiometric number of X Z = stoichiometric number of CO3 2 -

Table 4

Stoichiometric emission factor for process emissions from carbonate decomposition based on alkali earth oxides (Method B)

Oxide	Emission factor [t CO2/t Oxide]
CaO	0,785
MgO	1,092
BaO	0,287
general: XYOZ	Emission factor = [M(CO2)]/{Y × [M(x)] + Z × [M(O)]} X = alkali earth or alkali metal M(x) = molecular weight of X in [g/mol] M(CO2) = molecular weight of CO2 [g/mol] M(O) = molecular weight of O [g/mol] Y = stoichiometric number of X = 1 (for alkali earth metals) = 2 (for alkali metals) Z = stoichiometric number of O = 1

Table 5

Emission factors for process emissions from other process materials (production of iron or steel, and processing of ferrous metals)

²¹

Input or output material	Carbon content (t C/t)	Emission factor (t CO2/t)
Direct reduced iron (DRI)	0,0191	0,07
EAF carbon electrodes	0,8188	3,00
EAF charge carbon	0,8297	3,04
Hot briquetted iron (HBI)	0,0191	0,07
Oxygen steel furnace gas	0,3493	1,28
Petroleum coke	0,8706	3,19
Pig iron	0,0409	0,15
Iron / iron scrap	0,0409	0,15
Steel / steel scrap	0,0109	0,04

Global warming potentials for non-CO2 greenhouse gases

Table 6

Global warming potentials

Gas	Global warming potential
N2O	265 t CO2e/t N2O
CF4	6 630  t CO2e/t CF4
C2F6	11 100  t CO2e/t C2F6

Image omitted; see official source

Where NCVdry is the NCV of the absolute dry material, w is the water content (mass fraction) and Image omitted; see official source is the evaporation enthalpy of water. Using the same equation, the NCV for a given water content can be back-calculated from the dry NCV.

ANNEX III

Rules for attributing emissions to goods

A. PRINCIPLES FOR ATTRIBUTING DATA TO PRODUCTION PROCESSES

A.1.   Attribution if data is available

The methods for monitoring data per each production process shall be laid down in the monitoring plan in accordance with Annex II . They shall be regularly reviewed in order to improve the data quality, where possible, in line with point A of this Annex.

Where several measuring instruments of different quality are contributing to measurement results, and the sum of the production process data is different from the data determined separately for the installation, a uniform ‘reconciliation factor’ is applied for uniform correction to meet the total figure of the installation as follows:

RecF = DInst/Σ DPP	(Equation 41)

Where:

RecF is the reconciliation factor;

DInst is the data value determined for the installation as a whole; and

DPP are the data values for the different production processes.

The data for each production process are then corrected as follows, with DPP,corr being the corrected value of DPP:

DPP,corr = DPP × RecF	(Equation 42)

Where data for a specific data set are not available for each production process, inputs, outputs, and corresponding emissions shall be attributed based on the rules set in point A.2

A.2.   Attribution in case of lack of data or multi-functional processes.

In case of lack of data as referred to in point A.1 or in case of multi-functional processes, attribution will be based on a relevant underlying physical relationship, which refers to partitioning the input and output flows of a multi-functional process or facility in line with a relevant, quantifiable physical relationship between the process inputs and co-product outputs.

With the exception of the rules specified in points A.2.1, A.2.2 and A.2.3 of this Annex, inputs, outputs, and corresponding emissions shall be attributed based on the functional unit of individual goods produced.

The same attribution rule will be used to attribute both emissions and captured and stored emissions to goods.

In the case that a production process requires the application of different attribution rules, they must be applied in the following order:

• (1) attribution of emissions to heat flows;

• (2) attribution of emissions to waste gases;

• (3) functional unit attribution or molar ratio attribution, as applicable.

A.2.1.   Chemicals and fertilisers

If a chemical substance under the aggregated goods categories chemicals or fertilisers is produced as co-product of a multi-functional process, the attribution among the chemical substances shall be based on molar ratio.

The emissions of the production process shall be attributed to hydrogen based on molar proportions using the following equation:

Image omitted; see official source	(Equation 43)

Where:

Em i are either the direct or indirect emissions attributed to each co-product i produced over the reporting period, expressed in tonnes of CO2;

Em total are either the direct or indirect emissions of the whole production process over the reporting period, expressed in tonnes of CO2;

m i,prod is the mass of each co-product i produced in the installation over the reporting period, expressed in tonnes;

M i is the molar mass of each co-product i;

If the molar mass of one of the co-products is not known, the emissions will be attributed based on mass of the co-products.

A.2.2.   Heat flows and cogeneration

Measurable heat from processes other than combustion or partial oxidation of fuels

Measurable heat produced from exothermic chemical processes other than combustion and partial oxidation of fuels, such as in ammonia or nitric acid production, shall be assigned zero CO2e emissions.

Measurable heat produced in the installation other than by cogeneration

For measurable heat produced from the combustion of fuels within the installation except heat produced by cogeneration, the emission factor of the relevant fuel mix shall be determined and the emissions attributable to the production process shall be calculated as:

EmHeat = EFmix × Qconsumed/η	(Equation 44)

Where:

EmHeat is the heat-related emissions of the production process in t CO2;

EFmix is the emission factor of the respective fuel mix expressed in t CO2/TJ including emissions from flue gas cleaning, where applicable;

Qconsumed is the amount of measurable heat consumed in the production process expressed in TJ; and

η is the efficiency of the heat production process.

EFmix shall be calculated as:

EFmix = (Σ ADi × NCVi × EFi + EmFGC)/(Σ ADi × NCVi)	(Equation 45)

Where:

ADi are the annual activity data (i.e. quantities consumed) of the fuels i used for the measurable heat production expressed in tonnes or Nm³;

NCVi are the net calorific values of the fuels i expressed in TJ/t or TJ/Nm³;

EFi are the emission factors of the fuels i expressed in t CO2/TJ; and

EmFGC are the process emissions from flue gas cleaning expressed in t CO2.

Measurable heat produced in the installation by cogeneration

Where measurable heat and electricity are produced by cogeneration (i.e. by combined heat and power (CHP)), the relevant emissions attributed to measurable heat and electricity shall be determined as required by this point. The rules regarding electricity shall also apply to the production of mechanical energy, if relevant.

The emissions of a cogeneration unit shall be determined as follows:

Image omitted; see official source	(Equation 46)

Where:

EmCHP are the emissions of the cogeneration unit during the reporting period expressed in t CO2;

ADi are the annual activity data (i.e. quantities consumed) of the fuels i used for the CHP unit expressed in tonnes or Nm³;

NCVi are the net calorific values of the fuels i expressed in TJ/t or TJ/Nm³;

EFi are the emission factors of the fuels i expressed in t CO2/TJ; and

EmFGC are the process emissions from flue gas cleaning expressed in t CO2.

The energy input to the CHP unit shall be calculated in accordance with Equation 33. The respective average efficiencies over the reporting period of heat production and electricity (or mechanical energy, if applicable) production shall be calculated as follows:

Image omitted; see official source	(Equation 47)
Image omitted; see official source	(Equation 48)

Where:

ηheat is the average efficiency of heat production during the reporting period (dimensionless);

Qnet is the net amount of heat produced during the reporting period by the cogeneration unit expressed in TJ as determined in accordance with point C.1.2;

EIn is the energy input of fuels expressed in TJ;

ηel is the average efficiency of electricity production during the reporting period (dimensionless); and