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

For electricity, only direct emissions shall be monitored and reported. The emission factor for electricity shall be determined in accordance with Section D.2 of Annex III.

For electricity, direct emissions monitoring shall encompass:

— Any combustion emissions and process emissions from flue gas treatment.

Relevant precursors: none.

ANNEX III

A. PRINCIPLES

A.1.   Overall approach

1.For the purpose of determining embedded emissions of goods listed in Annex I to Regulation (EU) 2023/956, the following activities shall be performed:

(a) The production processes relating to goods produced in the installation shall be identified using the aggregated goods categories as defined in Section 2 of Annex II, as well as the relevant production routes listed in Section 3 of Annex II, taking into account the rules for setting system boundaries of production processes in accordance with Section 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 Section B of this Annex.

(c) Where measurable heat is imported to, produced in, consumed in or exported from the installation, net heat flows and the emissions associated with the production of that heat shall be monitored in line with the methods provided in Section C of this Annex.

(d) For the purpose of monitoring indirect emissions embedded in the goods produced, the consumption of electricity in the relevant production processes shall be monitored in line with the methods provided in Section D.1 of this Annex. Where electricity is produced within the installation or by a source with a direct technical link, the emissions associated with that electricity production shall be monitored in order to determine the emission factor for that electricity. Where the installation receives electricity from the grid, the emission factor for that electricity shall be determined according to Section D.2.3 of this Annex. 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 Section F of this Annex. Those attributed emissions shall be used to calculate the specific direct and indirect embedded emissions of the goods produced, applying the Section F of this Annex.

(f) Where Section 3 of Annex II defines relevant precursors for goods produced in the installations, making those goods ‘complex goods’, the embedded emissions of the relevant precursor shall be determined according to Section E of this Annex, and shall be added to the embedded emissions of the complex goods produced, by applying the rules provided in Section G of this Annex. Where precursors are themselves complex goods, that process shall be repeated recursively until no more precursors are at stake.

2.Where an operator cannot adequately determine actual data for one or more data sets, by applying methods provided in Section A.3 of this Annex, and where no other method for closing data gaps is available, the default values made available and published by the Commission for the transitional period may be used under the conditions specified in Article 4(3) of this Regulation. In that case, a short explanation of the reasons for not using actual data shall be added.

3.Monitoring shall cover a reporting period which ensures that non-representative data due to short-time fluctuations in the production processes and data gaps are avoided to the highest extent feasible. The default reporting period is a calendar year. However, the operator may choose as alternative:

(a) if the installation has a compliance obligation under an eligible monitoring, reporting and verification system, that system’s reporting period may be used, if it covers at least three months;

(b) the operator’s fiscal year provided such period ensures higher data quality than the use of the calendar year.

The embedded emissions of goods shall be calculated as average of the reporting period chosen.

4.Regarding emissions occurring outside the installation boundaries that are relevant for calculating embedded emissions, data for the latest available reporting period shall be used, as obtained from the supplier of the input (e.g. electricity, heat, precursor). Emissions occurring outside the installation boundaries include:

(a) indirect emissions where electricity is received from the grid;

(b) emissions from electricity and heat imported from other installations;

(c) embedded direct and indirect emissions of precursors received from other installations.

5.Emissions data over a full reporting period shall be expressed in tonnes CO2e rounded to full tonnes.

All parameters used to calculate the emissions shall be rounded to include all significant digits for the purpose of calculating and reporting emissions.

Specific direct and indirect embedded emissions shall be expressed in tonnes of CO2e 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:

(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 Section F of this Annex, 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 relevant precursors. (c) Indirect emissions at the installation level cover the emissions related to electricity consumption within the installation. (d) Indirect embedded emissions include the indirect emissions of the goods produced within the installation, and the indirect embedded emissions of relevant precursors. (e) For each parameter, an appropriate method in accordance with Section A.3 of this Annex shall be selected, ensuring that neither double counting nor data gaps occur.

(a) changes in the configuration of the instalation 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.

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 4 years after the reporting period. Those records may be disclosed to a reporting declarant.

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 CO2; (b) all biomass emissions in mass balances and for transferred CO2, where it is not possible to determine the biomass content in materials or fuels, the emissions shall be considered to be from fossil carbon.

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, the overarching principle shall be to always select the best available data source. For this purpose, the following guiding principles shall apply:

(a) Monitoring methods described in this Annex are preferred. If for a specific data set there is no monitoring method described in this Annex, or it would incur unreasonable costs or is technically not feasible, monitoring methods from another eligible monitoring, reporting and verification system may be used under the conditions specified in Article 4(2) of this Regulation, if they cover the required data set. Where such methods are not available, not technically feasible, or would incur unreasonable costs, indirect methods for determination of the data set in accordance with point 2 may be used. Where such methods are not available, not technically feasible, or would incur unreasonable costs, default values made available and published by the Commission for the transitional period may be used under the conditions specified in Article 4(3) of this Regulation.

(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 guidelines or other scientifically proven methodologies shall be used, limiting sampling and measurement bias.

(c) Within one method mentioned in point (a), measuring instruments or laboratory analyses under the operator’s control shall be preferred over measuring instruments or analyses under the control of another legal entity, such as the supplier of fuel or materials or trade partners regarding goods produced.

(d) 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 according to their use specification.

(e) 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 Section B.5.4.3 of this Annex shall apply.

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 that purpose 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 unreasononable costs, such better data source shall be applied without undue dalay. 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 used 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 Section H of this Annex, 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 methodology documentation.

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 methodology documentation 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 methodology documentation. 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 methodology documentation. 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.

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 20 per tonne of CO2e and costs shall include an appropriate depreciation period based on the economic lifetime of the equipment, where applicable.

The improvement factor shall be:

(a) the improvement of estimated uncertainty in a measurement, expressed in per cent, multiplied with the estimated related emissions over the reporting period. Related emissions means: (1) the direct emissions caused by the source stream or emission source concerned; (2) emissions attributed to a quantity of measurable heat; (3) the indirect emissions related to the quantity of electricity concerned; (4) embedded emissions of a material produced or of a precursor consumed;

(b) 1 % of the related emissions, where no improvement of measuring uncertainty is involved.

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 2 000 per year.

A.4.   Division of installations into production processes

Installations shall be divided into production processes with system boundaries which ensure that relevant inputs, outputs and emissions can be monitored in accordance with Sections B to E of this Annex and direct and indirect emissions can be attributed to groups of goods defined in Section 2 of Annex II, by applying the rules of Section F of this Annex.

Installations shall be divided into production processes as follows:

(a) A single production process shall be defined for each of the aggregated goods categories defined in Section 2 of Annex II that are relevant at the installation.

(b) By way of derogation from point (a), separate production processes shall be defined for each production route where different production routes in accordance with Section 3 of Annex II for the same aggregated goods category are applied in the same installation, or where the operator selects voluntarily different goods or groups of goods for separate monitoring. A more disaggregated definition of production processes may also be used where it is in accordance with an eligible monitoring, reporting and verification system applicable at the installation.

(c) By way of derogation from point (a), where at least a part of the precursors relevant for complex goods are produced in the same installation as the complex goods, and where the respective precursors are not transferred out of the installation for sale or use in other installations, the production of precursors and complex goods may be covered by a joint production process. Separate calculation of embedded emissions of the precursors shall be omitted in that case.

(d) The following sectoral derogations from point (a) may be applied: (1) Where two or more goods from the aggregated goods categories sintered ore, pig iron, FeMn, FeCr, FeNi, DRI, crude steel, or iron or steel products are produced in the same installation, the embedded emissions may be monitored and reported by defining one joint production process for all those goods. (2) Where two or more goods from the groups unwrought aluminium or aluminium products are produced in the same installation, the embedded emissions may be monitored and reported by defining one joint production process for all those goods. (3) For the production of mixed fertilisers, the monitoring and reporting for the respective production process may be simplified by determining one uniform value of embedded emissions per tonne of nitrogen contained in the mixed fertilisers, irrespective of the chemical form of nitrogen (ammonium, nitrate or urea forms).

(e) Where a part of the installation serves the production of goods not listed in Annex I to Regulation (EU) 2023/956, it is a recommended improvement to monitor that part as one additional production process for the purpose of corroborating the completeness of the installation’s total emissions data.

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 methodology documentation, taking into account the sector-specific requirements laid down in Section 2 of Annex II as well as Section B.9 of this Annex. The following principles shall apply:

B.2.   Choice of monitoring methodology

The applicable methodology shall be either:

By way of derogation, other methodologies may be used under the conditions specified in Articles 4(2), 4(3) and 5 of this Regulation.

The monitoring methodology that gives the most accurate and reliable results shall be chosen, except where sector-specific requirements in accordance with Section 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 monitoring methodology documentation shall clearly identify:

(a) for which source stream 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 Section B.3.4 of this Annex;

(b) for which emission source a measurement-based methodology is used, including the description of all relevant elements provided in Section B.6 of this Annex;

(c) by means of a suitable diagram and process description of the installation, evidence that there is neither double counting nor data gaps in the emissions of the installation.

The installation’s emissions shall be determined by

Where:

EmInst are the (direct) emissions of the installation expressed in tonnes CO2e;

Emcalc,i are the emissions from source stream i determined using a calculation-based methodology expressed in tonnes CO2e;

Emmeas,j are the emissions from emission source j determined using a measurement-based methodology expressed in tonnes CO2e; and

Emother,k Emissions determined by another method, index k expressed in tonnes CO2e.

B.3.   Formulae and parameters for the calculation-based methodology for CO2

Emissions shall be calculated separately for each source stream as follows:

Combustion emissions shall be calculated using the standard method as follows:

Where:

Emi are the emissions [t CO2] caused by fuel i;

EFi is the emission factor [t CO2/TJ] of fuel i;

ADi is the activity data [TJ] of fuel i, calculated as:

FQi is the fuel quantity consumed [t or m³] of fuel i;

NCVi is the net calorific value (lower heating value) [TJ/t or TJ/m³] of fuel i;

OFi is the oxidation factor (dimensionless) of fuel i, calculated as:

Cash is the carbon contained in ash and flue gas cleaning dust; and

Ctotal 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 m³);

(b) the EF is expressed in t CO2/t fuel or t CO2/m³ fuel, as applicable; and

(c) the NCV may be omitted from the calculation. However, it is a recommended improvement to report NCV for allowing consistency checking and monitoring of the energy efficiency of the whole production process.

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:

If the emission factor of a material or fuel expressed in t CO2/t is to be calculated from an analysed carbon content, the following equation is used:

Where:

f is the ratio of the molar masses of CO2 and C: f = 3,664 t CO2/t C.

As the emission factor of biomass shall be zero provided that the criteria given in Section 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:

Where:

EFpre,i is the preliminary emission factor of fuel i (i.e. emission factor assuming the total fuel is fossil); and

BFi is the biomass fraction (dimensionless) of fuel i.

For fossil fuels and where the biomass fraction is not known, BFi shall be set to the conservative value zero.

Process emissions shall be calculated using the standard method as follows:

Where:

ADj is the activity data [t of material] of material j;

EFj is the emission factor [t CO2/t] of material j; and

CFj is the conversion factor (dimension-less) of material j.

The conservative assumption that CFj = 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:

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 provided in Table 3 in Annex VIII shall be used, taking into account the composition of the material as determined in line with Section B.5 of this Annex.

— 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 in Annex VIII shall be used, taking into account the composition of the relevant material as determined in line with Section B.5 of this Annex.

For CO2 process emissions other than from carbonates, method A shall be applied.

The CO2 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:

Where:

ADk is the activity data [t] of material k; for outputs, ADk is negative;

f is the ratio of the molar masses of CO2 and C: f = 3,664 t CO2/t C; and

CCk 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 CO2/TJ, the following equation shall be used:

If the carbon content of a material or fuel k is calculated from an emission factor expressed in t CO2/t, the following equation shall be used:

For mixed fuels, meaning fuels which contain both fossil and biomass components or mixed materials, the biomass fraction may be taken into account, provided that the criteria provided in Section B.3.3 are met as follows:

Where:

CCpre,k is the preliminary carbon content of fuel k (i.e. emission factor assuming the total fuel is fossil); and

BFk is the 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 fraction of biomass in total output carbon shall not exceed the total fraction of biomass contained in input materials and fuels, except if the operator provides evidence of a higher biomass fraction in the output materials by a ‘trace the atom’ (stoichiometric) method or by ¹⁴C analyses.

Where biomass is used as a fuel for combustion, it shall fulfil the criteria of this section. Where the biomass used for combustion does not comply with these criteria, its carbon content shall be considered as fossil carbon.

In line with the formulae given in Sections B.3.1 to B.3.3 of this Annex, the following parameters shall be determined for each source stream:

— Minimum requirement: Fuel quantity (t or m³), Emission factor (t CO2/t or t CO2/m³). — Recommended improvement: Fuel quantity (t or m³), NCV (TJ/t or TJ/m³), Emission factor (t CO2/TJ), Oxidation factor, Biomass fraction, evidence for meeting the criteria of Section B.3.3.

— Minimum requirement: Activity data (t or m³), Emission factor (t CO2/t or t CO2/m³). — Recommended improvement: Activity data (t or m³), Emission factor (t CO2/t or t CO2/m³), conversion factor.

— 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 Section B.3.3.

B.4.   Requirements for activity data

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 methodology documentation:

(a) 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; (b) 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:

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.

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:

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

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

(2) direct readings from the measurement systems.

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

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

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

B.5.   Requirements for calculation factors for CO2

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

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.

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

Type I standard values shall be the following:

(a) standard factors provided in Annex VIII;

(b) standard factors contained in the latest IPCC guidelines for GHG inventories (⁵);

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

Type II standard values, shall be the following:

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

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

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

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

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

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

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

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

(b) net calorific value for specific coal types.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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:

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

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

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

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

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

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:

Where:

GHG Emtotal are the total annual GHG emissions in tonnes;

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

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

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

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

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

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:

Where:

conci is the concentration of gas component i.

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

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

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

Where:

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

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

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

— determination by continuous flow measurement at a representative point.

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:

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 with the duration of at least 6 months.

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

All measurements shall be carried out applying methods based on:

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

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

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

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

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

B.7.   Requirements for determining perfluorocarbon emissions

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

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

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

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

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

The following equations for determining PFC emissions shall be used:

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

C2F6 emissions [t] = CF4 emissions × FC2F6 (Equation 22)

Where:

AEM is the anode effect minutes/cell-day;

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

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

FC2F6 is the weight fraction of C2F6 [t C2F6/t CF4].

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

AEM = frequency × average duration (Equation 23)

Emission factor: The emission factor for CF4 (slope emission factor, SEFCF4) expresses the amount [kg] of CF4 emitted per tonne of aluminium produced per anode effect minute per cell-day. The emission factor (weight fraction FC2F6) of C2F6 expresses the amount [kg] of C2F6 emitted proportionate to the amount [kg] of CF4 emitted.

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

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

Technology	Emission factor for CF4 (SEFCF4) [(kg CF4/t Al)/(AE-Mins/cell-day)]	Emission factor for C2F6 (FC2F6) [t C2F6/ t CF4]
Legacy Point Feed Pre Bake (PFPB L)	0,122	0,097
Modern Point Feed Pre Bake (PFPB M)	0,104	0,057
Modern Point-Fed Prebake without fully automated anode effect intervention strategies for PFC emissions (PFPB MW)	– (*1)	– (*1)
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
(*1) The installation has to determine the factor by own measurements. If this is technically not feasible or involves unreasonable costs, the values for CWPB methodology shall be used.

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

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

C2F6 emissions [t] = CF4 emissions × FC2F6 (Equation 25)

Where:

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

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

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

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

FC2F6 is the weight fraction of C2F6 [t C2F6/t CF4].

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

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

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

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

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

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

B.8.   Requirements for CO2 transfers between installations

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

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

In the following cases CO2 originating from fossil carbon and originating from combustion or processes leading to process emissions, or which is imported from other installations, including in the form of inherent CO2, may be accounted for as not emitted:

(a) an installation for the purpose of CO2 capture which monitors emissions for the purpose of this Regulation or an eligible monitoring, reporting and verification system; (b) an installation or transport network with the purpose of long-term geological storage of CO2 which monitors emissions for the purpose of this Regulation or an eligible monitoring, reporting and verification system; (c) a storage site for the purpose of long-term geological storage which monitors emissions for the purpose of this Regulation or an eligible monitoring, reporting and verification system.

CO2 transferred to another installation for the purposes given in points 1 and 2 may be accounted for as not emitted only to the extent evidence is provided across the whole chain of custody to the storage site or installation of CO2 use and including any transport operators, of the fraction of CO2 actually stored or used for the production of chemically stable products compared to the total amount of CO2 transferred out of the originating installation.

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

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

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

For the determination of the quantity of CO2 transferred from one installation to another, a measurement-based methodology shall be used. For the amount of CO2 permanently chemically bound in products, a calculation-based methodology shall be used, preferably using a mass balance. The chemical reactions applied, and all relevant stoichiometric factors shall be laid down in the monitoring methodology documentation.

B.9.   Sector-specific requirements

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

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

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

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

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

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

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

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

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

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

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

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:

Where:

Cliprod is the amount of clinker produced expressed in tonnes;

Cemdeliv is the amount of cement deliveries expressed in tonnes;

CemSV are the cement stock variations expressed in tonnes;

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

Clis is the amount of clinker supplied expressed in tonnes;

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

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

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

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

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

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

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

Where:

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

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

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

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

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

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

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

Where:

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

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

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

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

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

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

C. HEAT FLOWS

C.1.   Rules for determining net measurable heat

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.

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

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

Where:

is the mass flow rate in kg/s;

is the volumetric flow rate in m³/s; and

v is the specific volume in m³/kg.

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

Where:

is the heat flow rate in kJ/s;

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

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

is the mass flow rate in kg/s.

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

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

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

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

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

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

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

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

Where:

Q is the amount of heat expressed in TJ;

ηH is the measured efficiency of heat production;

EIn is the energy input from fuels;

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

NCVi are the net calorific values of the fuels i.

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

Where:

LF is the load factor;

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

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

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

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

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

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

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

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

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

EmHeat = EFmix · Qconsumed/η (Equation 35)

Where:

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

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

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

η is the efficiency of the heat production process.

EFmix shall be calculated as:

EFmix = (Σ ADi · NCVi · EFi + EmFGC)/(Σ ADi · NCVi) (Equation 36)

Where:

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

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

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

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

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

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

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

Where:

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

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

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

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

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

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

Where:

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

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

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

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

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

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

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

Where:

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

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

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

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

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

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

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

Where:

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

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

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

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

Where:

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

Where a waste gas is part of the fuel mix used, and where the emission factor of the waste gas is higher than the standard emission factor of natural gas given in Table 1 of Annex VIII, that standard emission factor is used to calculate EFmix instead of the emission factor of the waste gas.

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