Commission Implementing Regulation (EU) 2023/1773 of 17 August 2023 laying down the rules for the application of Regulation (EU) 2023/956 of the European Parliament and of the Council as regards reporting obligations for the purposes of the carbon border adjustment mechanism during the transitional period (Text with EEA relevance)

Where it is technically not feasible or would incur unreasonable costs to determine quantities in stock by direct measurement, those quantities may be estimated based on one of the following:

• 1. data from previous years and correlated with appropriate activity levels for the reporting period;

• 1. documented procedures and respective data in audited financial statements for the reporting period.

Where the determination of quantities of products, materials or fuels for the entire reporting period is technically not feasible or would incur unreasonable costs, the next most appropriate day may be chosen to separate a reporting period from the following one. It shall be reconciled accordingly to the reporting period required. The deviations involved for each product, material or fuel shall be clearly recorded to form the basis of a value representative for the reporting period and to be considered consistently in relation to the next year.

B.4.2.   Operator’s control over measurement systems

The preferred method for determining quantities of products, materials or fuels shall be that the operator of the installation uses measurement systems under its own control. Measurement systems outside the operator’s own control, in particular if under the control of the supplier of the material or fuel, may be used in the following cases:

• 1. where the operator does not have an own measurement system available for determining the respective data set;

• 1. where determining the data set by the operator’s own measurement system is technically not feasible or would incur unreasonable costs;

• 1. where the operator has evidence that the measurement system outside the operator’s control gives more reliable results and is less prone to risks of misstatements.

In the case that measurement systems outside the operator’s own control are used, applicable data sources shall be the following:

• (1) amounts from invoices issued by a trade partner, provided that a commercial transaction between two independent trade partners takes place;

• (2) direct readings from the measurement systems.

B.4.3.   Requirements for measurement systems

A thorough understanding of the uncertainty associated with metering quantities of fuels and materials, including the influence of the operating environment and, where applicable, the uncertainty of stock determination shall be available. Measuring instrauments shall be chosen that ensure the lowest uncertainty available without incurring unreasonable costs and that are fit for the environment they are used in, in accordance with applicable technical standards and requirements. If available, instruments subject to legal metrological control shall be preferred. In this case, the maximum permissible error in service allowed by the relevant national legislation on legal metrological control for the relevant measuring task may be used as the uncertainty value.

Where a measuring instrument needs to be replaced because of malfunction or because calibration demonstrates that requirements are not met anymore, it shall be replaced by instruments that ensure meeting the same or a better uncertainty level compared to the existing instrument.

B.4.4.   Recommended improvement

It is considered a recommended improvement to achieve a measurement uncertainty comensurate with the total emissions of the source stream or emission source, with lowest uncertainty for the biggest parts of the emissions. For orientation purposes, for emissions of more than 500 000 t CO2 per year, the uncertainty over the full reporting period taking into account stock changes, if applicable, shall be 1,5 % or better. For emissions below 10 000 t CO2 per year, uncertainty lower than 7,5 % shall be acceptable.

B.5.   Requirements for calculation factors for CO2

B.5.1.   Methods for determining calculation factors

For the determination of calculation factors required for the calculation-based methodology, one of the following methods may be chosen:

• 1. use of standard values;

• 1. use of proxy data based on a empirical correlations between the relevant calculation factor and other properties better accessible to measurement;

• 1. use of values based on laboratory analysis.

Calculation factors shall be determined consistently with the state used for related activity data, referring to the fuel’s or material’s state in which the fuel or material is purchased or used in the emission causing process, before it is dried or otherwise treated for laboratory analysis. Where this incurs unreasonable costs or where higher accuracy can be achieved, activity data and calculation factors may be consistently reported referring to the state in which laboratory analyses are carried out.

B.5.2.   Applicable standard values

Type I standard values, shall be applicable only if no type II standard value is available for the same parameter and material or fuel.

Type I standard values shall be the following:

• (a) standard factors provided in Annex VIII;

• (b) standard factors contained in the latest IPCC guidelines for GHG inventories ([^E0007]);

• (c) values based on laboratory analyses carried out in the past, not older than 5 years and considered representative for the fuel or material.

Type II standard values, shall be the following:

• (a) standard factors used by the country where the installation is located for its latest national inventory submission to the Secretariat of the United Nations Framework Convention on Climate Change;

• (b) values published by national research institutions, public authorities, standardisation bodies, statistical offices, etc. for the purpose of more disaggregated emissions reporting than under the previous point;

• (c) values specified and guaranteed by the supplier of a fuel or material where there is evidence that the carbon content exhibits a 95 % confidence interval of not more than 1 %;

• (d) stoichiometric values for the carbon content and related literature values for the net calorific value (NCV) of a pure substance;

• (e) values based on laboratory analyses carried out in the past not older than two years and considered representative for the fuel or material.

In order to ensure consistency over time, any standard values used shall be laid down in the monitoring methodology documentation, and only changed if there is evidence that the new value is more adequate and representative for the fuel or material used than the previous one. Where the standard values change on an annual basis, the authoritative applicable source of that value shall be laid down in the monitoring methodology documentation instead of the value itself.

B.5.3.   Establishing correlations for determining proxy data

A proxy for the carbon content or emission factor may be derived from the following parameters, in combination with an empirical correlation determined at least once per year in accordance with the requirements for laboratory analyses given in Section B.5.4 of this Annex as follows:

• (a) density measurement of specific oils or gases, including those common to the refinery or steel industry;

• (b) net calorific value for specific coal types.

The correlation has to satisfy the requirements of good industrial practice and may be applied only to values of the proxy which fall into the range for which it was established.

B.5.4.   Requirements for laboratory analyses

Where laboratory analyses are required for determining properties (including moisture, purity, concentration, carbon content, biomass fraction, net calorific value, density) of products, materials, fuels or waste gases, or for establishing correlations between parameters for the purpose of indirect determination of required data, the analyses shall comply with the requirements of this section.

The result of any analysis shall be used only for the delivery period or batch of fuel or material for which the samples have been taken, and for which the samples were intended to be representative. When determining a specific parameter, the results of all analyses made shall be used with regard to that parameter.

B.5.4.1.   Use of standards

Any analyses, sampling, calibrations and validations for the determination of calculation factors shall be carried out by applying methods based on corresponding ISO standards. Where such standards are not available, the methods shall be based on suitable EN or national standards or requirements laid down in an eligible monitoring, reporting and verification system. Where no applicable published standards exist, suitable draft standards, industry best practice guidelines or other scientifically proven methodologies may be used, limiting sampling and measurement bias.

B.5.4.2.   Recommendations on sampling plan and minimum frequency of analyses

The minimum frequencies for analyses for relevant fuels and materials listed in Table 1 of this Annex shall be used. Another analysis frequency may be used in the following cases:

• (a) where the table does not contain an applicable minimum frequency;

• (b) where an eligible monitoring, reporting and verification system provides for another minimum analysis frequency for the same type of material or fuel;

• (c) where the minimum frequency listed in Table 1 of this Annex would incur unreasonable cost;

• (d) where it can be demonstrated that based on historical data, including analytical values for the respective fuels or materials in the reporting period immediately preceding the current reporting period, any variation in the analytical values for the respective fuel or material does not exceed 1/3 of the uncertainty in determining the activity data of the relevant fuel or material.

Where an installation operates for part of the year only, or where fuels or materials are delivered in batches that are consumed over more than one reporting period, a more appropriate schedule for analyses may be chosen, provided that it results in a comparable uncertainty as under the last point of the previous subparagraph.

Table 1

Minimum analyses frequencies

Fuel/material	Minimum frequency of analyses
Natural gas	At least weekly
Other gases, in particular synthesis gas and process gases such as refinery mixed gas, coke oven gas, blast-furnace gas, converter gas, oilfield, and gas field gas	At least daily – using appropriate procedures at different parts of the day
Fuel oils (for example light, medium, heavy fuel oil, bitumen)	Every 20 000 tonnes of fuel and at least six times a year
Coal, coking coal, coke, petroleum coke, peat	Every 20 000 tonnes of fuel/material and at least six times a year
Other fuels	Every 10 000 tonnes of fuel and at least four times a year
Untreated solid waste (pure fossil or mixed biomass/fossil)	Every 5 000 tonnes of waste and at least four times a year
Liquid waste, pre-treated solid waste	Every 10 000 tonnes of waste and at least four times a year
Carbonate minerals (including limestone and dolomite)	Every 50 000 tonnes of material and at least four times a year
Clays and shales	Amounts of material corresponding to emissions of 50 000 tonnes of CO2 and at least four times a year
Other materials (primary, intermediate, and final product)	Depending on the type of material and the variation, amounts of material corresponding to emissions of 50 000 tonnes of CO2 and at least four times a year

Samples shall be representative for the total batch or time period of deliveries for which they are taken. In order to ensure representativeness, the heterogenety of the material has to be taken into account, as well as all other relevant aspects such as the avilable sampling equipment, possible segregation of phases or local distribution of particle sizes, stability of samples, etc. The sampling method shall be laid down in the monitoring methodology documentation.

It is considered a recommended improvement to use a dedicated sampling plan for each relevant material or fuel, following applicable standards, containing the relevant information on methodologies for the preparation of samples, including information on responsibilities, locations, frequencies and quantities, and methodologies for the storage and transport of samples.

B.5.4.3.   Recommendations for laboratories

Laboratories used to carry out analyses for the determination of calculation factors shall be accredited in accordance with ISO/IEC 17025, for the relevant analytical methods. Laboratories not accredited may be used for the determination of calculation factors only where there is evidence that access to accredited laboratories is technically not feasible or would incur unreasonable costs, and that the non-accredited laboratory is sufficiently competent. A laboratory shall be considered sufficiently competent if it complies with all of the following:

• 1. it is economically independent of the operator, or at least organisationally shielded from influence by the management of the installation;

• 1. it applies the applicable standards for the analyses requested;

• 1. it employs personnel competent for the specific tasks assigned;

• 1. it appropriately manages the sampling and sample preparation, including control of sample integrity;

• 1. it regularly carries out quality assurance on calibrations, sampling and analytical methods, by suitable methods, including regular participation in proficiency testing schemes, applying analytical methods to certified reference materials, or inter-comparison with an accredited laboratory;

• 1. it manages equipment appropriately, including by maintaining and implementing procedures for calibration, adjustment, maintenance and repair of equipment, and record keeping thereof.

B.5.5.   Recommended methods for determination of calculation factors

It is considered a recommended improvement to apply standard values only for source streams which correspond to minor emission quantities, and to apply laboratory analyses for all major source streams. The following list presents the applicable methods in sequence of increasing data quality:

• 1. type I standard values;

• 1. type II standard values;

• 1. correlations for determining proxy data;

• 1. analyses carried out outside the operator’s control, e.g. by the supplier of the fuel or material, contained in purchase documents, without further information on the methods applied;

• 1. analyses in non-accredited laboratories, or in accredited laboratories, but with simplified sampling methods;

• 1. analyses in accredited laboratories, applying best practice regarding sampling.

B.6.   Requirements for a measurement-based methodology for CO2 and N2O

B.6.1.   General provisions

A measurement-based methodology requires the use of a Continuous Emission Measurement System (CEMS) installed at a suitable measurement point.

For the monitoring of N2O emissions, the use of the measurement-based methodology, is mandatory. For CO2 it shall be used only if there is evidence that it leads to more accurate data than the calculation-based methodology. The requirements on uncertainty of measurement systems pursuant to Section B.4.3 of this Annex shall apply.

CO emitted to the atmosphere shall be treated as the molar equivalent amount of CO2.

Where several emission sources exist in one installation and cannot be measured as one emission source, the operator shall measure emissions from those sources separately and add the results to obtain the total emissions of the gas in question over the reporting period.

B.6.2.   Method and calculation

B.6.2.1.   Emissions of a reporting period (annual emissions)

The total emissions from an emission source over the reporting period shall be determined by summing up over the reporting period all hourly values of the measured greenhouse gas concentration multiplied by the hourly values of the flue gas flow, where the hourly values shall be averages over all individual measurement results of the respective operating hour, applying the formula:

Image omitted; see official source

(Equation 16)

Where:

• GHG Emtotal are the total annual GHG emissions in tonnes;

• GHG conchourly,i are the hourly concentrations of GHG emissions in g/Nm³ in the flue gas flow measured during operation for hour or shorter reference period i;

• Vhourly,i is the flue gas volume in Nm³ for one hour or a shorter reference period i, determined by integrating the flow rate over the reference period; and

• HoursOp are the total number of hours (or shorter reference periods) for which the measurement-based methodology is applied, including the hours for which data has been substituted in accordance with Section B.6.2.6 of this Annex.

The index i refers to the individual operating hour (or reference periods).

Hourly averages for each measured parameter shall be calculated before further processing, by using all data points available for that specific hour. Where data for shorter reference periods can be generated without additional cost, those periods shall be used for the determination of the annual emissions.

B.6.2.2.   Determination of GHG concentration

The concentration of the GHG under consideration in the flue gas shall be determined by continuous measurement at a representative point through one of the following:

• — direct measurement of the concentration of the GHG;

• — indirect measurement: in the case of high concentration in the flue gas, the concentration of the GHG may be calculated using an indirect concentration measurement taking into account the measured concentration values of all other components i of the gas stream, using the following formula:

Image omitted; see official source

(Equation 17)

Where:

• conci is the concentration of gas component i.

B.6.2.3.   CO2 emissions from biomass

Where relevant, any CO2 amount stemming from biomass which complies with the criteria given in Section B.3.3 of this Annex may be subtracted from the total measured CO2 emissions, provided one of the following methods is used for the amount of biomass CO2 emissions:

• 1. a calculation-based methodology, including methodologies using analyses and sampling based on ISO 13833 (Stationary source emissions – Determination of the ratio of biomass (biogenic) and fossil-derived carbon dioxide – Radiocarbon sampling and determination);

• 1. another method based on a relevant standard, including ISO 18466 (Stationary source emissions – Determination of the biogenic fraction in CO2 in stack gas using the balance method);

• 1. another method allowed by an eligible monitoring, reporting and verification system.

B.6.2.4.   Determining CO2e emissions from N2O

In the case of N2O measurements, the total annual N2O emissions from all emissions sources, measured in tonnes to three decimal places, shall be converted to annual CO2e in rounded tonnes, using the following formula and the GWP values given in Annex VIII:

CO2e [t] = N2Oannual[t] × GWPN2O (Equation 18)

Where:

• N2Oannual is the total annual N2O emissions, calculated in accordance with Section B.6.2.1 of this Annex.

B.6.2.5.   Determination of flue gas flow

The flue gas flow may be determined by one of the following methods:

• — calculation by means of a suitable mass balance, taking into account all significant parameters on the input side, including for CO2 emissions at least input material loads, input airflow and process efficiency, and on the output side, including at least the product output and the concentration of oxygen (O2), sulphur dioxide (SO2) and nitrogen oxides (NOx);

• — determination by continuous flow measurement at a representative point.

B.6.2.6.   Treatment of measurement gaps

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 with the duration of at least 6 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:

• 1. ISO 20181:2023 Stationary source emissions – Quality assurance of automated measuring systems

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

• 1. ISO 14385-1:2014 Stationary source emissions – Greenhouse gases – Part 1: Calibration of automated measuring systems

• 1. ISO 14385-2:2014 Stationary source emissions – Greenhouse gases – Part 2: Ongoing quality control of automated measuring systems

• 1. 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 Section B.5.4.3 of this Annex 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 Sections B.4 to B.6 of this Annex 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:

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

• 1. 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 × FC2F6 (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

• FC2F6 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 FC2F6) 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 Annex 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 (FC2F6) [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)	– [^E0008]	– [^E0008]
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

The installation has to determine the factor by own measurements. If this is technically not feasible or involves unreasonable costs, the values for CWPB methodology shall be used.

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 × FC2F6 (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

• FC2F6 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 Annex VIII.

PFC emissions [t CO2e] = CF4 emissions [t] × GWPCF4 + C2F6 emissions [t] × GWPC2F6 (Equation 26)

B.8.   Requirements for CO2 transfers between installations

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 is transferred out of the installation as part of a source stream to another installation, it shall not be counted as emissions of the installation where it originates. However, where inherent CO2 is emitted (e.g. vented or flared) or transferred to entities that do not themselves monitor emissions for the purpose of this Regulation or an eligible monitoring, reporting and verification system, it shall be counted as emissions of the installation where it originates.

B.8.2.   Eligibility to deduct stored or used CO2

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:

• 1. if the CO2 is used within the installation or transferred out of the installation to any of the following:
• (a) an installation for the purpose of CO2 capture which monitors emissions for the purpose of this Regulation or an eligible monitoring, reporting and verification system;
• (b) an installation or transport network with the purpose of long-term geological storage of CO2 which monitors emissions for the purpose of this Regulation or an eligible monitoring, reporting and verification system;
• (c) a storage site for the purpose of long-term geological storage which monitors emissions for the purpose of this Regulation or an eligible monitoring, reporting and verification system.

• 1. 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 or an eligible monitoring, reporting and verification system, 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 the delegated act adopted pursuant to Article 12(3b) of Directive 2003/87/EC.

CO2 transferred to another installation for the purposes given in points 1 and 2 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.

If CO2 is used within the same installation for the purposes in points 1 and 2, the monitoring methods given in Sections 21 to 23 of Annex IV to Implementing Regulation (EU) 2018/2066 shall be applied.

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 methodology documentation. The amount of CO2 considered not emitted shall be reported in the communication 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 methodology documentation. The amount of CO2 received shall be reported in the communication 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 methodology documentation.

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 Section B.9.2.3 of this Annex.

• — 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 Section 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 Section B.5.4 of this Annex 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 Section B.6.2.5 of this Annex 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 Section B.9.3.2 of this Annex, the oxygen concentrations in the flue gas shall be measured, applying the requirements laid down in Section B.6.2.2 of this Annex. 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 Section A.4 of this Annex, 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 enthalpy of the transmitted flow in kJ/kg;

• hreturn is the 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:

• (a) 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;

• (b) 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:

• (a) 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;

• (b) 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:

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;

• 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.

Where measurable heat is recovered from non-measurable heat generated from fuels and used in production processes after that use, e.g. from exhaust gases, for avoiding double counting, the relevant amount of net measurable heat divided by a reference efficiency of 90 % is subtracted from the fuel input.

C.2.   Determining the fuel mix emission factor of measurable heat

Where a production process consumes measurable heat produced within the installation, the heat-related emissions shall be determined using one of the following methods.

C.2.1.   Emission factor of 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 35)

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 36)

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.

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 Annex VIII, that standard emission factor shall be used to calculate EFmix instead of the emission factor of the waste gas.

C.2.2.   Emission factor of 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 section. 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 37)

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 38)

Image omitted; see official source

(Equation 39)

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 Section C.1.2;

• EIn is the energy input as determined using Equation 33 expressed in TJ;

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

• Eel is the net electricity production of the cogeneration unit during the reporting period, expressed in TJ.

Where the determination of the efficiencies ηheat and ηel is technically not feasible or would incur unreasonable costs, values based on technical documentation (design values) of the installation shall be used. If no such values are available, conservative standard values of ηheat = 0,55 and ηel = 0,25 shall be used.

The attribution factors for heat and electricity from CHP shall be calculated as follows:

Image omitted; see official source

(Equation 40)

Image omitted; see official source

(Equation 41)

Where:

• FCHP,Heat is the attribution factor for heat (dimensionless);

• FCHP,El is the attribution factor for electricity (or mechanical energy, if applicable) (dimensionless);

• ηref,heat is the reference efficiency for heat production in a stand-alone boiler (dimensionless); and

• ηref,el is the reference efficiency of electricity production without cogeneration (dimensionless).

The appropriate fuel-specific reference efficiencies are given in Annex IX.

The specific emission factor of the CHP-related measurable heat to be used for the attribution of heat-related emissions to production processes shall be calculated as

EFCHP,Heat = EmCHP · FCHP,Heat/Qnet (Equation 42)

Where:

• EFCHP,heat is the emission factor for the production of measurable heat in the cogeneration unit expressed in t CO2/TJ; and

• Qnet is the net heat produced by the cogeneration unit expressed in TJ.

The specific emission factor of the CHP-related electricity to be used for the attribution of indirect emissions to production processes shall be calculated as:

EFCHP,El = EmCHP · FCHP,El/EEl,prod (Equation 43)

Where:

• EEl,prod is the electricity produced by the CHP unit.

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 Annex VIII, that standard emission factor is used to calculate EFmix instead of the emission factor of the waste gas.

C.2.3.   Emission factor of measurable heat produced outside the installation

Where a production process consumes measurable heat produced outside the installation, the heat-related emissions shall be determined using one of the following methods.

• 1. Where the installation producing the measurable heat is subject to an eligible monitoring, reporting and verification system, or where the operator of the installation consuming the measurable heat ensures by the means of relevant provisions of the heat delivery contract that the installation producing the heat carries out emission monitoring in line with this Annex, the emission factor of measurable heat shall be determined using relevant equations of Section C.2.1 or C.2.2, based on emission data provided by the operator of the installation producing the measurable heat.

• 1. Where the method pursuant to point 1 is not available, a standard value is used, based on the standard emission factor of the fuel most commonly used in the industrial sector of the country, assuming a boiler efficiency of 90 %.

D. ELECTRICITY

D.1.   Calculation of the emissions related to electricity

The emissions relating to electricity production or consumption for the purpose of calculating embedded emissions in accordance with section F.1 shall be calculated using the following equation:

Image omitted; see official source

(Equation 44)

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 or TJ; and

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

D.2.   Rules for determining the emission factor of electricity as imported goods

For determining the specific actual embedded emissions of electricity as imported goods, only direct emissions shall be applicable in accordance with Section 2 of Annex IV to Regulation (EU) 2023/956.

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

• (a) 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 of this Annex shall be used;

• (b) 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 of this Annex shall be used;

• (c) where a reporting declarant 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 of this Annex are fulfilled, the claimed lower values shall be determined on the basis of the available and reliable data provided;

• (d) a reporting declarant may apply actual embedded emissions instead of default values for the calculation of embedded emissions of the imported electricity, if the cumulative criteria (a) to (d) provided in Section 5 of Annex IV to Regulation (EU) 2023/956 are met, and the calculation is based on data determined according to this Annex by the producer of the electricity, calculated using Section D.2.3 of this Annex.

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

In accordance with Section 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 Commission. For the purpose of this Regulation, these CO2 emission factors shall be based on data from the International Energy Agency (IEA) and shall be provided by the Commission in the CBAM Transitional Registry.

D.2.2.   CO2 emission factor of the EU

Pursuant to Section 4.2.2 of Annex IV to Regulation (EU) 2023/956, the CO2 emission factor for the Union shall apply. For the purpose of this Regulation, the CO2 emission factor for the Union shall be based on data from the International Energy Agency (IEA) and shall be provided by the Commission in the CBAM Transitional Registry.

D.2.3.   CO2 emission factor based on reliable data demonstrated by the reporting declarant

For the purpose of point (c) of Section D.2 of this Annex, the reporting declarant shall provide the datasets from alternative official sources, including national statistics for the five-years period ending two years before the reporting.

In order to reflect the impact of decarbonisation policies, such as the increase in renewable energy production, as well as climatic conditions, such as particularly cold years, on the yearly electricity supply in the countries concerned, the reporting declarant shall calculate the CO2 emission factor on the basis of the weighted average of the CO2 emission factor for the five-years period ending two years before the reporting.

For this purpose, the reporting declarant shall calculate the yearly CO2 emission factors per fossil fuel technology and its respective gross electricity generation in the third country capable of exporting electricity to the EU, based on the following equation:

Image omitted; see official source

(Equation 45)

Where:

• Em el,y is the yearly CO2 emission factor for all fossil fuel technologies in the given year in the 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 reporting declarant shall calculate the CO2 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 46)

Where:

• Em el is the CO2 emission factor resulting from the moving average of the CO2 emission factors of the 5 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.

D.2.4.   CO2 emission factor based on actual CO2 emissions of the installation

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

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 as an input for the production of goods other than electricity

During the transitional period, emission factors for electricity shall be determined based on either:

• (a) the average emission factor of the country of origin electricity grid, based on data from the International Energy Agency (IEA) provided by the Commission in the CBAM Transitional Registry; or

• (b) any other emission factor of the country of origin electricity grid based on publicly available data representing either the average emission factor or the CO2 emission factor as referred to in Section 4.3 of Annex IV to Regulation (EU) 2023/956.

By derogation from the points (a) and (b), acctual emission factors for eletricity may be used for the cases specified in Sections D.4.1 to D.4.3.

D.4.1.   Emission factor of electricity produced in the installation other than by cogeneration

For electricity produced from the combustion of fuels within the installation 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)/Elprod (Equation 47)

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 Annex VIII, 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 in the installation by cogeneration

The emission factor of electricity production from by cogeneration shall be determined accrding to Section C.2.2 of this Annex.

D.4.3.   Emission factor of electricity produced outside the installation

• 1.Where electricity is received from a source with a direct technical link, and where all the relevant data is available, the emission factor of that electricity shall be determined applying sections D.4.1 or D.4.2 as appropriate.

• 2.Where the electricity is received from an electricity producer under a power purchase agreement, the emission factor for electricity determined in accordance with sections D.4.1 or D.4.2 may be used, as appropriate, where communicated by the electricity producer to the operator and made available pursuant to Annex IV.

E. MONITORING OF PRECURSORS

Where the description of production routes for the production processes defined for the installation indicates relevant precursors, the quantity of each precursor consumed within the installation’s production processes shall be determined in order to calculate the total embedded emissions of the complex goods produced in accordance with Section G of this Annex.

By way of derogation from the previous paragraph, where the production and use of a precursor are covered by the same production process, 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 installation from which the precursor is sourced. The methods used for determining the required data shall be laid down in the monitoring methodology documentation 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 the rules of Section A.4 of this Annex, 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 consumed in each production process of the installation for which it is a relevant precursor.

• 1. 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,
• — an exact address and its English transcript, and
• — the geographical coordinates of the installation;
• (c) the production route used as defined in Section 3 of Annex II;
• (d) the values of applicable specific parameters required for determining the embedded emissions, as listed in Section 2 of Annex IV;
• (e) specific embedded direct and indirect emissions of the precursor as average over the most recent available reporting period, expressed in tonnes CO2(e) CO2e per tonne of precursor;
• (f) the start and end date of the reporting period used by the installation from which the precursor was obtained;
• (g) the information on the carbon price due for the precursor, if relevant. The installation producing the precursor shall provide the relevant information, preferably by means of the electronic template mentioned in Article 3(5) and Annex IV.