Commission Implementing Regulation (EU) 2025/2547 ANNEX II

Rules for determining data set of production processes at installation level

ANNEX IISupplementary provisions

ANNEX II Rules for determining data set of production processes at installation level A.   PRINCIPLES AND GENERAL REQUIREMENTS A.1.    Overall approach 1. For the purpose of determining embedded emissions of goodsthe following activities shall be performed: (a) the production processes relating to the functional units produced in the installation shall be identified, taking into account the rules for setting system boundaries of production processes in accordance with point A.4 of this Annex; (b) at the level of the installation producing the goods, the direct emissions of the greenhouse gases specified in Annex II for those goods shall be monitored in line with the methods provided in point B of this Annex; (c) where measurable heat is imported to, produced in, consumed in or exported from the installation, net heat flows shall be monitored in line with the methods provided in point C of this Annex; (d) if the installation produces goods listed in Annex I to Regulation (EU) 2023/956, but not in Annex II to that Regulation, for the purpose of monitoring indirect emissions embedded in these goods, the consumption of electricity in the relevant production processes shall be monitored in line with the methods provided in point D.1 of this Annex. Where a direct technical link or a power purchase agreement is in place with the produceer of electricity in accordance with point 6, of Annex IV of that Regulation , the emissions associated with that electricity production shall be monitored in order to determine the emission factor for that electricity. Any quantities of electricity transferred between production processes or exported from the installation shall be monitored as well; (e) the direct emissions at the installations, with heat production and consumption, electricity production and consumption, and any relevant waste gas streams shall be attributed to the production processes associated with the goods produced by applying the rules provided in Annex III. Those attributed emissions shall be used to calculate the specific direct and, where relevant, indirect embedded emissions of the goods produced, applying the point B, of Annex III; (f) for those goods whose production processes include precursors, making those goods ‘complex goods’, the embedded emissions of the precursor shall be determined in accordance with point E, of this Annex, and shall be added to the embedded emissions of the complex goods produced, by applying the rules provided in point B, of Annex III. Where precursors are themselves complex goods, that process shall be repeated recursively until no more precursors are at stake. 2. An operator can either determine actual values of embedded emissions, or make use of the default values made available in accordance with Annex IV of Regulation (EU) 2023/956, or combine actual values and default values. 3. The embedded emissions of goods shall be calculated as average of the reporting period chosen. 4. For precursors produced outside the installation and originating in third countries and territories that are not exempted pursuant to point 1 of Annex III to Regulation (EU) 2023/956, actual data obtained from the operator of the installation producing the precursor shall be used only if the following conditions are met: (a) the data must be taken from a verification report that has been issued by a verifier having an accreditation in accordance with Article 18 of Delegated Regulation (EU) 2025/2551 valid at the time of issuing the verification report and for the sectoral scope required for the aggregated goods category of the precursor under consideration; and (b) the verification report must cover the reporting period during which the precursor was produced. 5. Where the operator does not have a verification report meeting conditions (a) and (b), the relevant default values, made available in accordance with Annex IV of Regulation (EU) 2023/956, for the precursor shall be used. 6. Emissions data over a full reporting period shall be expressed in tonnes CO 2 e rounded to full tonnes. 7. All parameters used to calculate the emissions shall be rounded to include all significant digits for the purpose of calculating and reporting emissions. 8. Specific direct and indirect embedded emissions shall be expressed in tonnes of CO 2 e per tonne of goods, rounded to include all significant digits, with a maximum of 5 digits after the comma. A.2.    Monitoring principles For the monitoring of actual data at installation level, and for data sets necessary for attributing emissions to goods, the following principles shall apply: 1. Completeness: The monitoring methodology shall cover all parameters necessary to determine the embedded emissions of the goods listed in Annex I to Regulation (EU) 2023/956 in accordance with the methods and formulae contained in this Annex. For this purpose, the following guiding principles shall apply: (a) direct emissions at installation level include combustion and process emissions; (b) direct embedded emissions include the attributed emissions of the relevant production process in accordance with Article 4 and Annex III, based on direct emissions at the installation, emissions related to relevant heat flows and to material flows between process system boundaries, including waste gases, if relevant. Direct embedded emissions furthermore include the direct embedded emissions of precursors; (c) indirect emissions, if relevant, at the installation level cover the emissions related to electricity consumption within the installation; (d) indirect embedded emissions, if relevant, include the indirect emissions of the goods produced within the installation, and the indirect embedded emissions of precursors; (e) for each parameter, an appropriate method in accordance with point A.3 of this Annex shall be selected, ensuring that neither double counting nor data gaps occur. 2. Consistency and comparability: Monitoring and reporting shall be consistent and comparable over time. To that end, the selected methods shall be laid down in a monitoring plan so that the methods are used consistently. The methodology shall be changed only if objectively justified. Relevant reasons include: (a) changes in the configuration of the installation in the technology used, in the input materials and fuels, or in the goods produced; (b) new data sources or monitoring methods have to be introduced because of changes of trade partners responsible for data used in the monitoring methodology; (c) the accuracy of the data can be improved, data flows can be simplified or the control system can be improved. 3. Transparency: Monitoring data including assumptions, references, activity data, emission factors, calculation factors, data on embedded emissions of purchased precursors, measurable heat and electricity, default values of embedded emissions, and any other data relevant for the purpose of this Annex, shall be obtained, recorded, compiled, analysed and documented in a transparent manner that enables a verifier accredited in accordance with Article 18 of Regulation (EU) 2023/956 to verify with reasonable assurance that the data is free of material misstatements. Documentation shall include a record of all changes in the functioning of the installation, of the monitoring methodology and control system applied as documented in the monitoring plan. 4. Complete and transparent records shall be kept at the installation of all data relevant for determining embedded emissions of the goods produced, including necessary supporting documents, for at least six years after the reporting period. 5. Accuracy: The chosen monitoring methodology shall ensure that emission determination is neither systematically nor knowingly inaccurate. Any source of inaccuracies shall be identififed and reduced as far as possible. Due diligence shall be exercised to ensure that the calculation and measurement of emissions exhibit the highest achievable accuracy. Where data gaps have occurred or are expected to be unavoidable, substitute data shall consist of conservative estimates. Further cases where emissions data shall be based on conservative estimates include: (a) carbon monoxide (CO) emitted to the atmosphere shall be calculated as the molar equivalent amount of CO 2 ; (b) all biomass emissions should be treated like fossil emission, unless evidence for meeting the criteria for zero rating in accordance with point B.3.3 of this Annex is provided. 6. Integrity of methodology: The chosen monitoring methodology shall enable reasonable assurance of the integrity of emission data to be reported. Emissions shall be determined using the appropriate monitoring methodologies set out in this Annex. Reported emission data shall be free from material misstatement, avoid bias in the selection and presentation of information, and provide a credible and balanced account of the embedded emissions of installation’s produced goods. 7. Data quality: a control system to ensure the quality of the data to be reported shall be applied. 8. Cost-effectiveness: In selecting a monitoring methodology, the improvements from greater accuracy shall be balanced against additional costs. Monitoring and reporting of emissions shall aim for the highest achievable accuracy, unless that is technically not feasible or incurs unreasonable costs. 9. Continuous improvement: Operators shall regularly check if the monitoring plan and its monitoring methodologies can be improved. If the verifier provides any recommendations for improvement in the verification report, the operator shall consider them for implementation within a reasonable timeframe, unless the improvement would incur unreasonable costs or would be technically not feasible. A.3.    Methods representing the best available data source 1. For the determination of embedded emissions of goods, and for underlying data sets, such as emissions related to individual source streams or emission sources, quantities of measurable heat and electricity, the overarching principle shall be to always select the best available data source. For this purpose, the following guiding principles shall apply: (a) if for a specific data set there is no monitoring method referred to in this Annex, or it would incur unreasonable costs or is technically not feasible, default values in made available in accordance with Annex IV of Regulation (EU) 2023/956 shall be used; (b) for direct or indirect determination methods, a method is deemed suitable where it is ensured that any metering, analyses, sampling, calibrations, and validations for the determination of the specific data set are carried out by applying methods defined in relevant EN or ISO standards. Where such standards are not available, national standards may be used. Where no applicable published standards exist, suitable draft standards, industry best practice or other scientifically proven methodologies shall be used, limiting sampling and measurement bias; (c) measuring instruments shall be selected such that they exhibit the lowest uncertainty in use without incurring unreasonable costs. Instruments under legal metrological control are preferred, except where other instruments with significantly lower uncertainty in use are available. Instruments shall be used only in environments appropriate to their use specification; (d) where laboratory analyses are used, or where laboratories carry out sample treatment, calibrations, method validations, or activities relating to continuous emissions measurements, the requirements of point B.5.4.3. 2. Indirect determination methods: Where no direct determination method is available for a required data set, in particular for cases where net measurable heat going into different production processes needs to be determined, an indirect determination method may be used, such as: (a) calculation based on a known chemical or physical process, using appropriate accepted literature values for the chemical and physical properties of substances involved, appropriate stoichiometric factors and thermodynamic properties such as reaction enthalpies, as appropriate; (b) calculation based on the installation’s design data such as the energy efficiencies of technical units or calculated energy consumption per unit of product; (c) correlations based on empirical tests for determining estimation values for the required data set from non-calibrated equipment or data documented in production protocols. For the purpose of point (c) it shall be ensured that the correlation satisfies the requirements of good engineering practice and that it is applied only to determine values which fall into the range for which it was established. The validity of such correlations shall be evaluated at least once a year. 3. To determine the best available data sources, the data source highest in the ranking presented under point 1 and already available at the installation shall be selected. However, where it is technically feasible to apply a data source higher in the ranking without incurring unreasonable costs, such better data source shall be applied without undue delay. Where different data sources are available for the same data set at the same level in the ranking presented under point 1, the data source which ensures the clearest data flow with lowest inherent risk and control risk regarding misstatements shall be chosen. 4. The data sources chosen under point 3 shall be defined in the monitoring plan for use for the determination and reporting of embedded emissions. 5. To the extent feasible without incurring unreasonable costs, for the purpose of the control system in accordance with point A.5, additional data sources or methods for determining data sets shall be identified to allow corroboration of data sources under point 3. The selected data sources, if any, shall be laid down in the monitoring plan. 6. Recommended improvements: It shall be checked regularly, but at least once per year, whether new data sources have become available, for the purpose of improving the monitoring methods. In the case that such new data sources are considered more accurate in accordance with the ranking presented under point 1, they shall be laid down in the monitoring plan and be applied from the earliest date possible. 7. Technical feasibility: Where a claim is made that applying a specific determination methodology is technically not feasible, a justification for this fact shall be laid down in the monitoring plan. It shall be re-assessed during the regular checks in line with point 6. That justification shall be based on whether the installation has technical resources capable of meeting the needs of a proposed data source or monitoring method that can be implemented in the required time for the purposes of this Annex. Those technical resources shall include availability of required techniques and technology. 8. Unreasonable costs: Where a claim is made that applying a specific determination methodology for a data set incurs unreasonable costs, a justification for this fact shall be laid down in the monitoring plan. It shall be re-assessed during the regular checks in line with point 6. The unreasonable nature of the costs shall be determined as follows. (a) Costs for determining a specific data set is considered unreasonable where the operator's cost estimation exceeds the benefit of a specific determination methodology. To that end, the benefit shall be calculated by multiplying an improvement factor with a reference price of EUR 80 per tonne of CO 2 e and costs shall include an appropriate depreciation period based on the economic lifetime of the equipment, where applicable. (b) The improvement factor shall be: — the improvement of estimated uncertainty in a measurement, expressed in per cent, multiplied with the estimated related emissions over the reporting period; — 1 % of the related emissions, where no improvement of measuring uncertainty is involved; — related emissions means: — the direct emissions caused by the source stream or emission source concerned; — emissions attributed to a quantity of measurable heat; — the indirect emissions related to the quantity of electricity concerned; — embedded emissions of a material produced or of a precursor consumed. (c) Measures relating to the improvement of an installation’s monitoring methodology shall not be deemed to incur unreasonable costs up to an accumulated amount of EUR 4 000 per year. A.4.    Specific provisions of division of installations into production processes For the goods under the aggregated goods categories crude steel, iron and steel products, unwrought aluminium and aluminium products, where different functional units that only differ in size or shape are produced with the same precursors in types, quantities and proportions, a single multifunctional production process shall be defined for that group of goods and attribution rules set out in point A.2 of Annex III shall apply. For the goods under the aggregated goods categories fertilisers, where different functional units are produced with the same precursors in types, quantities and proportions or are composed by the same substance, and only differ in concentrations, a single multifunctional production process shall be defined for that group of goods and attribution rules set out in point A.2 of Annex III shall apply. A.5.    Monitoring plan Template containing the minimum elements to be contained in the monitoring plan: 1. the date and version number of the monitoring plan; 2. a description of the installation and production processes carried out by the installation; 3. a list of all relevant goods produced by CN code and functional unit, and where applicable the specific compositions in terms of clinker content and nitrogen content, including precursors not covered by separate production processes in accordance with Article 4; 4. a list of all CBAM production processes and routes carried out at the installation and list of goods delivered per production processes; 5. if relevant, a list of non-CBAM goods produced per production process and the quantity produced; 6. a list of the relevant CBAM benchmarks to be used for the determination of the free allocation adjustment for all relevant goods produced; 7. the methods for monitoring data per each production process including: (a) a detailed description of the calculation-based methodology when applied, including a list of input data and calculation formulae; (b) a description of the measurement systems used, and exact location of the measuring instruments to be used for each of the source streams to be monitored; 8. the methods for determining calculation factors and sampling plan for each source stream, if applicable; 9. a list of source streams and emission sources and their description for each production process; 10. a list of source streams for which the calculation-based standard method or the mass balance method is used, including the detailed description of the determination of each relevant parameter provided in point B.3.4; 11. a list of emission sources for which a measurement-based methodology is used, including the description of all relevant elements provided in point B.6; 12. a description of the monitoring methodology as far as perfluorocarbons from primary aluminium production are monitored; 13. a suitable diagram and process description of the installation including the system boundaries of the installations and different production processes, providing evidence that there is neither double counting nor data gaps in the emissions of the installation; 14. the precursors used in each production process and if produced in other installation, name and country of origin of their suppliers; 15. whether any zero-rated fuels are used and how the operator demonstrates the applicability of zero-rating of the fuels; 16. whether measurable heat is imported from or exported to other installations, and an identification of those installations, a detailed description of the methods to determine the emissions attributed to the heat flows for each production process; 17. for indirect emissions, whether electricity is produced inside the installation; if so, whether electricity is: (a) produced by co-generation; (b) produced by separate generation; (c) produced from fossil or renewable sources; (d) exported from the system boundaries of a production process; 18. where the indirect emissions are determined on the basis of actual emissions, the information needed to provide the relevant parts of the elements of evidence laid down in point D.4.3; 19. where the embedded emissions of electricity imported into the customs territory of the Union are determined on the basis of actual emissions, the information needed to provide the elements of evidence laid down in point D.2.4, including, where this information is not directly available to the operator, how the operator plans to receive it; 20. whether waste gases are produced and used in the installation, or imported from or exported to other installations, and an identification of those installations; 21. whether CO 2 capture, storage and/or use in accordance with point B.8.2 apply, the identity and contact data of a responsible person of the receiving installations or transport infrastructure or entities to which it is transferred, and the monitoring methodology in accordance with point B.8.3; 22. a control system to ensure the data quality which shall include, where applicable: (a) quality assurance of the relevant measurement equipment ensuring that all relevant measuring equipment is calibrated, adjusted, and checked at regular intervals including prior to use, and checked against measurement standards traceable to international measurement standards, where available, and proportionate to the relevance of the measurement equipment; (b) risk assesment where sources of risks of errors in the data flow from primary data to final data are identified; (c) quality assurance of information technology systems ensuring that the relevant systems are designed, documented, tested, implemented, controlled and maintained in a way that ensures processing reliable, accurate and timely data in accordance with the risks identified in the risk assessment; (d) segregation of duties in the data flow activities and control activities, as well as management of necessary competencies; (e) internal reviews and validation of data; (f) corrections and corrective action; (g) control of outsourced processes; (h) keeping records and documentation including the management of document versions. B.   MONITORING OF DIRECT EMISSIONS AT INSTALLATION LEVEL B.1.    Completeness of source streams and emission sources The boundaries of the installation and its production processes shall be clearly known to the operator and defined in the monitoring plan, taking into account the sector-specific requirements laid down in point 3 of Annex I and point B.9. The following principles shall apply: (a) as a minimum, all relevant greenhouse gas emissions emission sources and source streams associated directly or indirectly with the production of goods listed in point 2 of Annex I shall be covered; (b) all emissions from regular operations shall be included, as well as from abnormal events, including start-up, shut-down and emergency situations, over the reporting period; (c) emissions from mobile machinery for transportation purposes shall be excluded. B.2.    Choice of monitoring methodology The applicable methodology shall be either of the following: (a) the calculation-based methodology, which consists in determining emissions from source streams on the basis of activity data obtained by means of measurement systems and additional parameters from laboratory analyses or standard values. The calculation-based methodology may be implemented in accordance with the standard method or the mass balance method; (b) the measurement-based methodology, which consists in determining emissions from emission sources by means of continuous measurement of the concentration of the relevant greenhouse gas in the flue gas and of the flue gas flow. The monitoring methodology that gives the most accurate and reliable results shall be chosen, except where sector-specific requirements in accordance with point B.9 require one particular methodology. The applied monitoring methodology may be a combination of methodologies such that different parts of the installation’s emissions are monitored by either of the applicable methodologies. The installation’s emissions shall be determined by (Equation 4) Where: Em Inst are the (direct) emissions of the installation expressed in tonnes CO 2 e; Em calc,i are the emissions from source stream i determined using a calculation-based methodology expressed in tonnes CO 2 e; Em meas,j are the emissions from emission source j determined using a measurement-based methodology expressed in tonnes CO 2 e. B.3.    Formulae and parameters for the calculation-based methodology for CO 2 B.3.1.    Standard method Emissions shall be calculated separately for each source stream as follows: B.3.1.1.    Combustion emissions Combustion emissions shall be calculated using the standard method as follows: (Equation 5) Where: Em i are the emissions [t CO 2 ] caused by fuel i; EF i is the emission factor [t CO 2 /TJ] of fuel i; AD i is the activity data [TJ] of fuel i , calculated as (Equation 6); FQ i is the fuel quantity consumed [t or m 3 ] of fuel i; NCV i is the net calorific value (lower heating value) [TJ/t or TJ/m 3 ] of fuel i; OF i is the oxidation factor (dimensionless) of fuel i , calculated as: (Equation 7); C ash is the carbon contained in ash and flue gas cleaning dust; and C total is the total carbon contained in the fuel combusted. The conservative assumption that OF = 1 may always be used in order to reduce monitoring efforts. Provided that this leads to a higher accuracy, the standard method for combustion emissions may be modified as follows: (a) the activity data is expressed as fuel quantity (i.e. in t or m 3 ); (b) the EF is expressed in t CO 2 /t fuel or t CO 2 /m 3  fuel, as applicable; and (c) the NCV may be omitted from the calculation. If the emission factor of a fuel i is to be calculated from the analyses of carbon content and NCV, the following equation shall be used: (Equation 8) Where: CC i is the carbon content of the fuel i. If the emission factor of a material or fuel expressed in t CO 2 /t is to be calculated from an analysed carbon content, the following equation is used: (Equation 9) Where: f is the ratio of the molar masses of CO 2 and C: f = 3,664 t CO 2 /t C. As the emission factor of biomass shall be zero provided that the criteria given in point B.3.3 are met, this fact may be taken into account for mixed fuels (i.e. fuels which contain both fossil and biomass components) as follows: (Equation 10) Where: EF pre,i is the preliminary emission factor of fuel i (i.e. emission factor assuming the total fuel is fossil) and BF i is the biomass fraction (dimensionless) of fuel i . For fossil fuels and where the biomass fraction is not known, BF i shall be set to the conservative value zero. B.3.1.2.    Process emissions Process emissions shall be calculated using the standard method as follows: (Equation 11) Where: AD j is the activity data [t of material] of material j ; EF j is the emission factor [t CO 2 /t] of material j ; and CF j is the conversion factor (dimension-less) of material j . The conservative assumption that CF j = 1 may always be used in order to reduce monitoring efforts. In the case of mixed process input materials which contain inorganic as well as organic forms of carbon, the operator may choose either: — to determine a total preliminary emission factor for the mixed material by analysing the total carbon content ( CC j ), and using a conversion factor and, where applicable a biomass fraction and net calorific value related to that total carbon content; or — to determine the organic and inorganic contents separately and treat them as two separate source streams. Considering the available measurement systems for activity data and methods for determining the emission factor, for emissions from the decomposition of carbonates, the method giving the more accurate results shall be chosen for each source stream from the following two methods: — method A (Input based): The emission factor, conversion factor and activity data shall be related to the amount of material input into the process. The standard emission factors of pure carbonates as set out in Table 3 of point G shall be used, taking into account the composition of the material as determined in line with point B.5; — method B (Output based): The emission factor, conversion factor and activity data shall be related to the amount of output from the process. The standard emission factors of metal oxides after decarbonatisation as provided in Table 4 of point G shall be used, taking into account the composition of the relevant material as determined in line with point B.5. For CO 2 process emissions other than from carbonates, method A shall be applied. B.3.2.    Mass balance method The CO 2 quantities relevant for each source stream shall be calculated based on the carbon content in each material, without distinguishing fuels and process materials. Carbon leaving the installation in products instead of being emitted is taken into account by output source streams, which have therefore negative activity data. The emissions corresponding to each source stream shall be calculated as follows: (Equation 12) Where: AD k is the activity data [t] of material k ; for outputs, AD k is negative; f is the ratio of the molar masses of CO 2 and C: f = 3,664 t CO 2 /t C; and CC k is the carbon content of material k (dimensionless and positive). If the carbon content of a fuel k is calculated from an emission factor expressed in t CO 2 /TJ, the following equation shall be used: (Equation 13) If the carbon content of a material or fuel k is calculated from an emission factor expressed in t CO 2 /t, the following equation shall be used: (Equation 14) For mixed fuels, the zero-rated biomass fraction may be taken into account, provided that the criteria provided in point B.3.3 are met as follows: (Equation 15) Where: CC pre,k is the preliminary carbon content of fuel k (i.e. emission factor assuming the total fuel is fossil) and BF k is the zero rated biomass fraction of fuel k (dimensionless). For fossil fuels or materials and where the biomass fraction is not known, BF shall be set to the conservative value zero. Where biomass is used as input material or fuel, and output materials contain carbon, the overall mass balance shall treat the biomass fraction conservatively, meaning that the total mass of carbon corresponding to the zero-rated carbon fractions of the carbon contained in all relevant output materials is not lower than the total mass of zero-rated fractions of the carbon contained in input materials and fuels, except if the operator provides evidence of a lower biomass fraction in the output materials by a ‘trace the atom’ (stoichiometric) method or by carbon-14 analyses. B.3.3.    Criteria for zero-rating of biomass emissions 1. Where biomass is used as a fuel for combustion, it shall fulfil the criteria of this point. Where the biomass used for combustion does not comply with these criteria, its carbon content shall be considered as fossil carbon. 2. The biomass shall comply with the sustainability and the greenhouse gas emissions saving criteria laid down in Article 29(2) to (7) and (10) of Directive (EU) 2018/2001. 3. By way of derogation from point 2, biomass contained in or produced from waste and residues, other than agricultural, aquaculture, fisheries and forestry residues shall fulfil only the criteria laid down in Article 29(10) of Directive (EU) 2018/2001. This point shall also apply to waste and residues that are first processed into a product before being further processed into fuels. 4. Electricity, heating and cooling produced from municipal solid waste shall not be subject to the criteria laid down in Article 29(10) of Directive (EU) 2018/2001. 5. The criteria laid down Article 29(2) to (7) and (10) of Directive (EU) 2018/2001 shall apply irrespective of the geographical origin of the biomass. 6. The compliance with the criteria laid down in paragraphs Article 29(2) to (7) and (10) of Directive (EU) 2018/2001 shall be assessed in accordance with Article 30 and Article 31(1) of that Directive. The criteria may be considered complied with if the operator provides evidence of the purchase of a quantity of biofuel, bioliquid or biogas connected to the cancellation of the respective quantity in the Union Database set up pursuant to Article 31a or a proof of sustainability by a recognised voluntary scheme. B.3.4.    Relevant parameters In line with the formulae given in points B.3.1 to B.3.2, the following parameters shall be determined for each source stream: (a) Standard method, combustion: — Minimum requirement: Fuel quantity (t or m 3 ), Emission factor (t CO 2 /t or t CO 2 /m 3 ). — Recommended improvement: Fuel quantity (t or m 3 ), NCV (TJ/t or TJ/m 3 ), Emission factor (t CO 2 /TJ), Oxidation factor, Biomass fraction, evidence for meeting the criteria of point B.3.3. (b) Standard method, process emissions: — Minimum requirement: Activity data (t or m 3 ), Emission factor (t CO 2 /t or t CO 2 /m 3 ). — Recommended improvement: Activity data (t or m 3 ), Emission factor (t CO 2 /t or t CO 2 /m 3 ), conversion factor. (c) Mass balance: — Minimum requirement: Material quantity (t), Carbon content (t C/t material). — Recommended improvement: Material quantity (t), Carbon content (t C/t material), NCV (TJ/t), biomass fraction, evidence for meeting the criteria of point B.3.3. B.4.    Requirements for activity data B.4.1.    Continual or batch-wise metering Where quantities of fuels or materials, including goods or intermediate products, have to be determined for a reporting period, one of the following methods may be chosen and laid down in the monitoring plan: (a) based on continual metering at the process where the material is consumed or produced; (b) based on aggregation of metering of quantities separately (batch-wise) delivered or produced taking into account relevant stock changes. For this purpose the following shall apply: — the quantity of fuel or material consumed during the reporting period shall be calculated as the quantity of fuel or material imported during the reporting period, minus the quantity of fuel or material exported, plus the quantity of fuel or material in stock at the beginning of the reporting period, minus the quantity of fuel or material in stock at the end of the reporting period; — the production levels of goods or intermediate products shall be calculated as the quantity exported during the reporting period, minus the quantity imported, minus the quantity of product or material in stock at the beginning of the reporting period, plus the quantity of product or material in stock at the end of the reporting period. For avoiding any double counting, products of a production process returned into the same production process are deducted from production levels. 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: (a) data from previous years and correlated with appropriate activity levels for the reporting period; (b) 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: — where the operator does not have an own measurement system available for determining the respective data set; — where determining the data set by the operator’s own measurement system is technically not feasible or would incur unreasonable costs; — 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: — amounts from invoices issued by a trade partner, provided that a commercial transaction between two independent trade partners takes place; — 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 instruments 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 CO 2 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 CO 2 per year, uncertainty lower than 7,5 % shall be acceptable. B.5.    Requirements for calculation factors for CO 2 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: (a) use of standard values; (b) use of proxy data based on a empirical correlations between the relevant calculation factor and other properties better accessible to measurement; (c) 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: — standard factors provided in point G; — standard factors contained in the latest IPCC guidelines for GHG inventories  ( 1 ) ; — values based on laboratory analyses carried out in the past, not older than five years and considered representative for the fuel or material. Type II standard values, shall be the following: — 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; — values published by national research institutions, public authorities, standardisation bodies, statistical offices etc. for the purpose of more disaggregated emissions reporting than under the point (a); — 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 %; — stoichiometric values for the carbon content and related literature values for the NCV of a pure substance; — 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 plan, 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 plan 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 point B.5.4 as follows: — density measurement of specific oils or gases, including those common to the refinery or steel industry; — 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 point. 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. 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 point is recommended to be used. Another analysis frequency may be used in the following cases: — where Table 1 does not contain an applicable minimum frequency; — where the minimum frequency listed in Table 1 would incur unreasonable cost; — 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 set out in point (c) of the first 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 CO 2 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 CO 2 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 is recommended to be laid down in the monitoring plan. 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 are recommended to 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 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: — it is economically independent of the operator; — it applies the applicable standards for the analyses requested; — it employs personnel competent to carry out the specific tasks assigned; — it appropriately manages the sampling and sample preparation, including control of sample integrity; — 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; — 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: — type I standard values; — type II standard values; — correlations for determining proxy data; — 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; — analyses in non-accredited laboratories, or in accredited laboratories, but with simplified sampling methods; — analyses in accredited laboratories, applying best practice regarding sampling. B.6.    Requirements for a measurement-based methodology for CO 2 and N 2 O 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 N 2 O emissions, the use of the measurement-based methodology, is mandatory. For CO 2 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 point B.4.3 of this Annex shall apply. CO emitted to the atmosphere shall be treated as the molar equivalent amount of CO 2 . 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: (Equation 16) Where: GHG Em total are the total annual GHG emissions in tonnes; GHG conc hourly,i are the hourly concentrations of GHG emissions in g/Nm 3 in the flue gas flow measured during operation for hour or shorter reference period i ; V hourly,i is the flue gas volume in Nm 3 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 point B.6.2.6. 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: (Equation 17) Where: conc i is the concentration of gas component i . B.6.2.3.    CO 2 emissions from biomass Where relevant, any CO 2 amount stemming from biomass which complies with the criteria given in point B.3.3 may be subtracted from the total measured CO 2 emissions, provided one of the following methods is used for the amount of biomass CO 2 emissions: — 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); — another method based on a relevant standard, including ISO 18466 (Stationary source emissions – Determination of the biogenic fraction in CO 2 in stack gas using the balance method). B.6.2.4.    Determining CO 2 e emissions from N 2 O In the case of N 2 O measurements, the total annual N 2 O emissions from all emissions sources, measured in tonnes to three decimal places, shall be converted to annual CO 2 e in rounded tonnes, using the following formula and the GWP values given in point G: CO 2 e [t] = N 2 O annual [t] × GWP N 2 O (Equation 18) Where: N 2 O annual is the total annual N 2 O emissions, calculated in accordance with point B.6.2.1. 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 CO 2 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 (O 2 ), sulphur dioxide (SO 2 ) and nitrogen oxides (NO x ); — 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: (Equation 19) Where: 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 CO 2 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 CO 2 e 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 CF 4 and C 2 F 6 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: CF 4 emissions [t] = AEM × (SEF CF 4 /1 000) × Pr Al (Equation 21) C 2 F 6 emissions [t] = CF 4 emissions × F C 2 F 6 (Equation 22) Where: AEM is the anode effect minutes/cell-day; SEF CF 4 is the slope emission factor expressed in (kg CF 4 /t Al produced)/(anode effect minutes/cell-day)]. Where different cell-types are used, different SEF may be applied as appropriate; Pr Al is the production of primary aluminium [t] during the reporting period; and F C 2 F 6 is the weight fraction of C 2 F 6 [t C 2 F 6 /t CF 4 ]. 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 CF 4 (slope emission factor, SEF CF 4 ) expresses the amount [kg] of CF 4 emitted per tonne of aluminium produced per anode effect minute per cell-day. The emission factor (weight fraction F C 2 F 6 ) of C 2 F 6 expresses the amount [kg] of C 2 F 6 emitted proportionate to the amount [kg] of CF 4 emitted. Minimum requirement: Technology-specific emission factors from Table 2 of this point are used. Recommended improvement: Installation-specific emission factors for CF 4 and C 2 F 6 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 CF 4 (SEF CF 4 ) [(kg CF 4 /t Al)/(AE-Mins/cell-day)] Emission factor for C 2 F 6 (F C 2 F 6 ) [t C 2 F 6 /t CF 4 ] 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) –  ( 2 ) –  ( 2 ) 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: CF 4 emissions [t] = OVC × (AEO/CE) × Pr Al × 0,001 (Equation 24) C 2 F 6 emissions [t] = CF 4 emissions × F C 2 F 6 (Equation 25) Where: OVC is the overvoltage coefficient (‘emission factor’) expressed in kg CF 4 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 [%]; Pr Al is the annual production of primary aluminium [t]; and F C 2 F 6 is the weight fraction of C 2 F 6 [t C 2 F 6 /t CF 4 ]. 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 CF 4 [(kg CF 4 /t Al)/(mV)] and C 2 F 6 [t C 2 F 6 /t CF 4 ] 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 CF 4 [(kg CF 4 /t Al)/mV] Emission factor for C 2 F 6 [t C 2 F 6 /t CF 4 ] Centre Worked Prebake (CWPB) 1,16 0,121 Side Worked Prebake (SWPB) 3,65 0,252 B.7.3.    Determination of CO 2 e emissions CO 2 e emissions shall be calculated from CF 4 and C 2 F 6 emissions as follows, using the global warming potentials listed in point G of this Annex. PFC emissions [t CO 2 e] = CF 4 emissions [t] × GWP CF 4 + C 2 F 6 emissions [t] × GWP C 2 F 6 (Equation 26) B.8.    Requirements for CO 2 transfers B.8.1.    CO 2 contained in gases (‘inherent CO 2 ’) Inherent CO 2 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 CO 2 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 CO 2 (1) In the following cases CO 2 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 CO 2 , may be accounted for as not emitted, provided they comply with point (2): (a) if the CO 2 is used within the installation or transferred out of the installation to any of the following: — an installation for the purpose of CO 2 capture which monitors emissions for the purpose of this Regulation; — an installation or transport network with the purpose of long-term geological storage of CO 2 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 CO 2 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 CO 2 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  ( 3 ) . (2) CO 2 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 CO 2 use and including any transport operators, of the fraction of CO 2 actually stored or used for the production of chemically stable products compared to the total amount of CO 2 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 CO 2 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 CO 2 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 CO 2 was received shall be clearly laid down in the monitoring plan. The amount of CO 2 received shall be reported in the emission report pursuant to Annex IV. For the determination of the quantity of CO 2 transferred from one installation to another, a measurement-based methodology shall be used. For the amount of CO 2 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 CO 2 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  ( 4 ) shall be applied. B.9.    Sector-specific requirements B.9.1.    Additional rules for combustion units Combustion emissions shall cover all CO 2 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 CO 2 process emissions from flue gas scrubbing, in particular CO 2 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 CO 2 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 (CaSO 4 × 2H 2 O) to CO 2 emitted: 0,2558 t CO 2 /t gypsum. B.9.1.2.    De-NO x If urea is used as reduction agent in a de-NOx unit, process CO 2 emissions from its use shall be calculated using method A, applying an emission factor based on the stoichiometric ratio of 0,7328 t CO 2 /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 CO 2 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 CO 2 /Nm 3 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: (Equation 27) Where: Cli prod is the amount of clinker produced expressed in tonnes; Cem deliv is the amount of cement deliveries expressed in tonnes; Cem SV are the cement stock variations expressed in tonnes; CCR is the clinker to cement ratio (tonnes clinker per tonne cement); Cli s is the amount of clinker supplied expressed in tonnes; Cli d is the amount of clinker dispatched expressed in tonnes; and Cli SV 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 CO 2 /t clinker shall be applied. B.9.2.3.    Emissions related to discarded dust CO 2 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 CO 2 /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: (Equation 28) Where: EF CKD is the emission factor of partially calcined cement kiln dust [t CO 2 /t CKD]; EF Cli is the installation-specific emission factor of clinker [t CO 2 /t clinker]; and d is the degree of CKD calcination (released CO 2 as % of total carbonate CO 2 in the raw mix). B.9.3.    Additional rules for emissions from nitric acid production B.9.3.1.    General rules for N 2 O measurement N 2 O emissions shall be determined using a measurement-based methodology. N 2 O concentrations in the flue gas from each emission source shall be measured at a representative point, after the NO x /N 2 O abatement equipment, where abatement is used. Techniques capable of measuring N 2 O 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: V flue gas flow [Nm 3 /h] = V air × (1 – O 2 , air )/(1 – O 2 , flue gas ) (Equation 29) Where: V air is the total input air flow in Nm 3 /h at standard conditions; O 2,air is the volume fraction of O 2 in dry air (= 0,2095); and O 2,flue gas is the volume fraction of O 2 in the flue gas. V air 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 (O 2 ) 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: (Equation 30) Where: is the mass flow rate in kg/s; is the volumetric flow rate in m 3 /s; and v is the specific volume in m 3 /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: (Equation 31) Where: is the heat flow rate in kJ/s; h flow is the specific enthalpy of the transmitted flow in kJ/kg; h return is the specific enthalpy of the return flow in kJ/kg; and 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, h return 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: (Equation 32) (Equation 33) Where: Q is the amount of heat expressed in TJ; η H is the measured efficiency of heat production and transmission; E In is the energy input from fuels; AD i are the annual activity data (i.e. quantities consumed) of the fuels  i ; and NCV i are the net calorific values of the fuels  i . The value of η H 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: (Equation 34) Where: L F is the load factor; E In the energy input as determined using Equation 33 over the reporting period; and E Max 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 % ( η Ref,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 CO 2 e 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: (Equation 35) Where: Em el are the emissions related to electricity produced or consumed, expressed in t CO 2 ; E el is the electricity produced or consumed expressed in MWh; and EF el is the emission factor for electricity applied, expressed in t CO 2 /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 CO 2 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 CO 2 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 CO 2 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.    CO 2 emission factor based on specific default values In accordance with point 4.2.1 of Annex IV to Regulation (EU) 2023/956, CO 2 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.    CO 2 emission factor of the EU Pursuant to point 4.2.2 of Annex IV to Regulation (EU) 2023/956, the CO 2 emission factor for the Union shall apply. D.2.3.    CO 2 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 CO 2 emission factor calculated on the basis of equations 36 and 37 is lower than the CO 2 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 CO 2 emission factor shall be calculated on the basis of the average of the yearly CO 2 emission factors for the most recent five-years period for which reliable data is available. For this purpose, the yearly CO 2 emission factors shall be calculated , based on the following equation: (Equation 36) Where: Em el , y is the yearly CO 2 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 CO 2 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 CO 2 emission factor shall be calculated as a moving average of those years starting with the current year minus two, based on the following equation: (Equation 37) Where: Em el is the CO 2 emission factor resulting from the moving average of the yearly CO 2 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 CO 2 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 CO 2 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 EF El shall be determined based on the relevant fuel mix and the emissions attributable to the electricity production shall be calculated as: EF El = (Σ AD i × NCV i × EF i + Em FGC )/El prodIs (Equation 38) Where: AD i are the annual activity data (i.e. quantities consumed) of the fuels i used for the electricity production expressed in tonnes or Nm 3 ; NCV i are the net calorific values of the fuels i expressed in TJ/t or TJ/Nm 3 ; EF i is the emission factors of the fuels i expressed in t CO 2 /TJ; Em FGC are the process emissions from flue gas cleaning expressed in t CO 2 ; and El prod 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 EF El 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: (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: (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 CO 2 e 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 CO 2 e 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 CO 2 /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  ( 5 ) n.a. World Business Council for Sustainable Development – Cement Sustainability Initiative (WBCSD CSI) Carbon monoxide 155,2  ( 6 ) 10,1 J. Falbe and M. Regitz, Römpp Chemie Lexikon , Stuttgart, 1995 Methane 54,9  ( 7 ) 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 CO 2 /TJ] NCV [GJ/t] Source Wood / Wood waste (air dry  ( 8 ) ) 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 GL  ( 9 ) Other liquid biofuels 79,6 27,4 IPCC 2006 GL Landfill gas  ( 10 ) 54,6 50,4 IPCC 2006 GL Sludge gas  ( 11 ) 54,6 50,4 IPCC 2006 GL Other biogas  ( 11 ) 54,6 50,4 IPCC 2006 GL Municipal waste (biomass fraction)  ( 12 ) 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 CO 2 /t Carbonate] CaCO 3 0,440 MgCO 3 0,522 Na 2 CO 3 0,415 BaCO 3 0,223 Li 2 CO 3 0,596 K 2 CO 3 0,318 SrCO 3 0,298 NaHCO 3 0,524 FeCO 3 0,380 General Emission factor = [M(CO 2 )]/{Y × [M(x)] + Z × [M(CO 3 2 - )]} X = metal M(x) = molecular weight of X in [g/mol] M(CO 2 ) = molecular weight of CO 2 in [g/mol] M(CO 3 2 - ) = molecular weight of CO 3 2 - in [g/mol] Y = stoichiometric number of X Z = stoichiometric number of CO 3 2 - Table 4 Stoichiometric emission factor for process emissions from carbonate decomposition based on alkali earth oxides (Method B) Oxide Emission factor [t CO 2 /t Oxide] CaO 0,785 MgO 1,092 BaO 0,287 general: X Y O Z Emission factor = [M(CO 2 )]/{Y × [M(x)] + Z × [M(O)]} X = alkali earth or alkali metal M(x) = molecular weight of X in [g/mol] M(CO 2 ) = molecular weight of CO 2 [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)  ( 13 ) Input or output material Carbon content (t C/t) Emission factor (t CO 2 /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-CO 2 greenhouse gases Table 6 Global warming potentials Gas Global warming potential N 2 O 265 t CO 2 e/t N 2 O CF 4 6 630  t CO 2 e/t CF 4 C 2 F 6 11 100  t CO 2 e/t C 2 F 6 ( 1 )   United Nations International Panel on Climate Change (IPCC): IPCC Guidelines for National Greenhouse Gas Inventories . ( 2 )   The installation operator 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. ( 3 )   Commission Delegated Regulation (EU) 2024/2620 of 30 July 2024 supplementing Directive 2003/87/EC of the European Parliament and of the Council as regards the requirements for considering that greenhouse gases have become permanently chemically bound in a product ( OJ L, 2024/2620 4.10.2024, ELI: http://data.europa.eu/eli/reg_del/2024/2620/oj ). ( 4 )   Commission Implementing Regulation (EU) 2018/2066 of 19 December 2018 on the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council and amending Commission Regulation (EU) No 601/2012 ( OJ L 334, 31.12.2018, p. 1 , ELI: https://data.europa.eu/eli/reg_impl/2018/2066/oj ). ( 5 )   This value is the preliminary emission factor, i.e. before application of a biomass fraction, if applicable. ( 6 )   Based on NCV of 10,12 TJ/t. ( 7 )   Based on NCV of 50,01 TJ/t. ( 8 )   The given emission factor assumes around 15 % water content of the wood. Fresh wood can have water content of up to 50 %. For determining the NCV of completely dry wood, the following equation shall be used: Where NCV dry is the NCV of the absolute dry material, w is the water content (mass fraction) and 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. ( 9 )   The NCV value is taken from Annex III of Directive (EU) 2018/2001. ( 10 )   For landfill gas, sludge gas and other biogas: Standard values refer to pure Biomethane. For arriving at the correct standard values, a correction is required for the methane content of the gas. ( 11 )   Based on NCV of 50,01 TJ/t. ( 12 )   The IPCC guidelines also give values for the fossil fraction of municipal waste: EF = 91,7 t CO 2 /TJ; NCV = 10 GJ/t. ( 13 )    IPCC 2006 Guidelines for National Greenhouse Gas Inventories.