ANNEX I

Minimum content of the monitoring plan (Article 12(1))

1.   MINIMUM CONTENT OF THE MONITORING PAN FOR INSTALLATIONS

The monitoring plan for an installation shall contain at least the following information:

(1)

general information on the installation: (a) a description of the installation and activities carried out by the installation to be monitored, containing a list of emissions sources and source streams to be monitored for each activity carried out within the installation and meeting the following criteria: (i) the description must be sufficient for demonstrating that neither data gaps nor double counting of emissions occur; (ii) a simple diagram of the emission sources, source streams, sampling points and metering equipment must be added where requested by the competent authority or where such diagram simplifies describing the installation or referencing emission sources, source streams, measuring instruments and any other parts of the installation relevant for the monitoring methodology including data flow activities and control activities; (b) a description of the procedure for managing the assignment of responsibilities for monitoring and reporting within the installation, and for managing the competences of responsible personnel; (c) a description of the procedure for regular evaluation of the monitoring plan's appropriateness, covering at least the following: (i) checking the list of emissions sources and source streams, ensuring completeness of the emission sources and source streams and that all relevant changes in the nature and functioning of the installation will be included in the monitoring plan; (ii) assessing compliance with the uncertainty thresholds for activity data and other parameters, where applicable, for the applied tiers for each source stream and emission source; (iii) assessing potential measures for improvement of the monitoring methodology applied; (d) a description of the written procedures of the data flow activities pursuant to Article 58, including a diagram where appropriate for clarification; (e) a description of the written procedures for the control activities established pursuant to Article 59; (f) where applicable, information on relevant links with activities undertaken in the framework of the Community eco-management and audit scheme (EMAS) established pursuant to Regulation (EC) No 1221/2009 of the European Parliament and of the Council (1), systems covered by harmonised standard ISO 14001:2004 and other environmental management systems including information on procedures and controls with relevance to greenhouse gas emissions monitoring and reporting; (g) the version number of the monitoring plan and the date from which that version of the monitoring plan is applicable; (h) the category of the installation;

(2)

a detailed description of the calculation-based methodologies where applied, consisting of the following: (a) a detailed description of the calculation-based methodology applied, including a list of input data and calculation formulae used, a list of the tiers applied for activity data and all relevant calculation factors for each of the source streams to be monitored; (b) where applicable and where the operator intends to make use of simplification for minor and de-minimis source streams, a categorisation of the source streams into major, minor and de-minimis source streams; (c) a description of the measurement systems used, and their measurement range, specified uncertainty and exact location of the measuring instruments to be used for each of the source streams to be monitored; (d) where applicable, the default values used for calculation factors indicating the source of the factor, or the relevant source, from which the default factor will be retrieved periodically, for each of the source streams; (e) where applicable, a list of the analysis methods to be used for the determination of all relevant calculation factors for each of the source streams, and a description of the written procedures for those analyses; (f) where applicable, a description of the procedure underpinning the sampling plan for the sampling of fuel and materials to be analysed, and the procedure used to revise the appropriateness of the sampling plan; (g) where applicable, a list of laboratories engaged in carrying out relevant analytical procedures and, where the laboratory is not accredited as referred to in Article 34(1) a description of the procedure used for demonstrating the compliance with equivalent requirements in accordance with Article 34(2) and (3);

(3)

where a fall-back monitoring methodology is applied in accordance with Article 22, a detailed description of the monitoring methodology applied for all source streams or emission sources, for which no tier methodology is used, and a description of the written procedure used for the associated uncertainty analysis to be carried out;

(4)

a detailed description of the measurement-based methodologies, where applied, including the following: (a) a description of the measurement method including descriptions of all written procedures relevant for the measurement and the following: (i) any calculation formulae used for data aggregation and used to determine the annual emissions of each emission source; (ii) the method for determining whether valid hours or shorter reference periods for each parameter can be calculated, and for substitution of missing data in accordance with Article 45; (b) a list of all relevant emission points during typical operation, and during restrictive and transition phases, including breakdown periods or commissioning phases, supplemented by a process diagram where requested by the competent authority; (c) where flue gas flow is derived by calculation, a description of the written procedure for that calculation for each emission source monitored using a measurement-based methodology; (d) a list of all relevant equipment, indicating its measurement frequency, operating range and uncertainty; (e) a list of applied standards and of any deviations from those standards; (f) a description of the written procedure for carrying out the corroborating calculations in accordance with Article 46, where applicable; (g) a description of the method, how CO2 stemming from biomass is to be determined and subtracted from the measured CO2 emissions, and of the written procedure used for that purpose, where applicable; (h) where applicable and where the operator intends to make use of simplification for minor emission sources, a categorisation of the emission sources into major and minor emission sources;

(5)

in addition to elements listed in point 4, a detailed description of the monitoring methodology where N2O emissions are monitored, where appropriate in the form of description of the written procedures applied, including a description of the following: (a) the method and parameters used to determine the quantity of materials used in the production process and the maximum quantity of material used at full capacity; (b) the method and parameters used to determine the quantity of product produced as an hourly output, expressed as nitric acid (100 %), adipic acid (100 %), caprolactam, glyoxal and glyoxylic acid per hour respectively; (c) the method and parameters used to determine the N2O concentration in the flue gas from each emission source, its operating range, and its uncertainty, and details of any alternative methods to be applied where concentrations fall outside the operating range and the situations when this may occur; (d) the calculation method used to determine N2O emissions from periodic, unabated sources in nitric acid, adipic acid, caprolactam, glyoxal and glyoxylic acid production; (e) the way in which or the extent to which the installation operates with variable loads, and the manner in which the operational management is carried out; (f) the method and any calculation formulae used to determine the annual N2O emissions and the corresponding CO2(e) values of each emission source; (g) information on process conditions that deviate from normal operations, an indication of the potential frequency and the duration of such conditions, as well as an indication of the volume of the N2O emissions during the deviating process conditions such as abatement equipment malfunction;

(6)

a detailed description of the monitoring methodology as far as perfluorocarbons from primary aluminium production are monitored, where appropriate in the form of a description of the written procedures applied, including the following: (a) where applicable, the dates of measurement for the determination of the installation-specific emission factors SEFCF4 or OVC, and FC2F6, and a schedule for future repetitions of that determination; (b) where applicable, the protocol describing the procedure used to determine the installation-specific emission factors for CF4 and C2F6, showing also that the measurements have been and will be carried out for a sufficiently long time for measured values to converge, but at least for 72 hours; (c) where applicable, the methodology for determining the collection efficiency for fugitive emissions at installations for primary aluminium production; (d) a description of cell type and type of anode;

(7)

a detailed description of the monitoring methodology where transfer of inherent CO2 as part of a source stream in accordance with Article 48, transfer of CO2 in accordance with Article 49, or transfer of N2O in accordance with Article 50 are carried out, where appropriate in the form of a description of the written procedures applied, including the following: (a) where applicable, the location of equipment for temperature and pressure measurement in a transport network; (b) where applicable, procedures for preventing, detecting and quantification of leakage events from transport networks; (c) in the case of transport networks, procedures effectively ensuring that CO2 is transferred only to installations which have a valid greenhouse gas emission permit, or where any emitted CO2 is effectively monitored and accounted for in accordance with Article 49; (d) identification of the receiving and transferring installations according to the installation identification code recognised in accordance with Regulation (EU) No 1193/2011; (e) where applicable, a description of continuous measurement systems used at the points of transfer of CO2 or N2O between installations transferring CO2 or N2O or the determination method in accordance with Articles 48, 49 or 50; (f) where applicable, a description of the conservative estimation method used for determining the biomass fraction of transferred CO2 in accordance with Article 48 or 49; (g) where applicable, quantification methodologies for emissions or CO2 released to the water column from potential leakages as well as the applied and possibly adapted quantification methodologies for actual emissions or CO2 released to the water column from leakages, as specified in section 23 of Annex IV.

2.   MINIMUM CONTENT OF MONITORING PLANS FOR AVIATION EMISSIONS

1.

The monitoring plan shall contain the following information for all aircraft operators: (a) the identification of the aircraft operator, call sign or other unique designator used for air traffic control purposes, contact details of the aircraft operator and of a responsible person at the aircraft operator, contact address, the administering Member State, the administering competent authority; (b) an initial list of aircraft types in its fleet operated at the time of the submission of the monitoring plan and the number of aircraft per type, and an indicative list of additional aircraft types expected to be used including, where available, an estimated number of aircraft per type as well as the source streams (fuel types) associated with each aircraft type; (c) a description of procedures, systems and responsibilities used to update the completeness of the list of emission sources over the monitoring year for the purpose of ensuring the completeness of monitoring and reporting of the emissions of owned aircraft as well as leased-in aircraft; (d) a description of the procedures used to monitor the completeness of the list of flights operated under the unique designator by aerodrome pair, and the procedures used for determining whether flights are covered by Annex I to Directive 2003/87/EC for the purpose of ensuring completeness of flights and avoiding double counting; (e) a description of the procedure for managing and assigning responsibilities for monitoring and reporting, and for managing the competences of responsible personnel; (f) a description of the procedure for regular evaluation of the monitoring plan's appropriateness, including any potential measures for the improvement of the monitoring methodology and related procedures applied; (g) a description of the written procedures of the data flow activities as required by Article 58, including a diagram, where appropriate, for clarification; (h) a description of the written procedures for the control activities established under Article 59; (i) where applicable, information on relevant links with activities undertaken in the framework of EMAS, systems covered by harmonised standard ISO 14001:2004 and other environmental management systems, including information on procedures and controls with relevance to greenhouse gas emissions monitoring and reporting; (j) the version number of the monitoring plan and the date from which that version of the monitoring plan is applicable; (k) confirmation if the aircraft operator intends to make use of the simplification pursuant to Article 28a(6) of Directive 2003/87/EC.

2.

The monitoring plan shall contain the following information for aircraft operators which are not small emitters in accordance with Article 55(1) or which do not intend to use a small emitter tool in accordance with Article 55(2): (a) a description of the written procedure to be used for defining the monitoring methodology for additional aircraft types which an aircraft operator expects to use; (b) a description of the written procedures for monitoring fuel consumption in every aircraft, including: (i) the chosen methodology (Method A or Method B) for calculating the fuel consumption; and where the same method is not applied for all aircraft types, a justification for that methodology, as well as a list specifying which method is used under which conditions; (ii) procedures for the measurement of fuel uplifts and fuel in tanks, a description of the measuring instruments involved and the procedures for recording, retrieving, transmitting and storing information regarding measurements, as applicable; (iii) the method for the determination of density, where applicable; (iv) justification of the chosen monitoring methodology, in order to ensure lowest levels of uncertainty, according to Article 56 (1); (c) a list of deviations for specific aerodromes from the general monitoring methodology as described in point (b) where it is not possible for the aircraft operator due to special circumstances to provide all the required data for the required monitoring methodology; (d) emission factors used for each fuel type, or in the case of alternative fuels, the methodologies for determining the emission factors, including the methodology for sampling, methods of analysis, a description of the laboratories used and of their accreditation and/or of their quality assurance procedures; (e) a description of the procedures and systems for identifying, assessing and handling data gaps pursuant to Article 66(2).

3.   MINIMUM CONTENT OF MONITORING PLANS FOR TONNE-KILOMETRE DATA

The monitoring plan for tonne-kilometre data shall contain the following information:

(a)	the elements listed in point 1 of section 2 of this Annex;

(b)

a description of the written procedures used for determining tonne-kilometre data per flight, including: (i) the procedures, responsibilities, data sources and calculation formulae for determining and recording the distance per aerodrome pair; (ii) the tier used for determining the mass of passengers including the checked in baggage; in the case of tier 2, a description of the procedure for obtaining the mass of passengers and baggage is to be provided; (iii) a description of the procedures used to determine the mass of freight and mail, where applicable; (iv) a description of the measurement devices used for measuring the mass of passengers, freight and mail as applicable.

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(1)   OJ L 342, 22.12.2009, p. 1.

ANNEX II

Tier definitions for calculation-based methodologies related to installations (Article 12(1))

1.   DEFINITION OF TIERS FOR ACTIVITY DATA

The uncertainty thresholds in Table 1 shall apply to tiers relevant to activity data requirements in accordance with point (a) of Article 28(1) and the first subparagraph of Article 29(2), and Annex IV, of this Regulation. The uncertainty thresholds shall be interpreted as maximum permissible uncertainties for the determination of source streams over a reporting period.

Where Table 1 does not include activities listed in Annex I to Directive 2003/87/EC and the mass balance is not applied, the operator shall use the tiers listed in Table 1 under ‘Combustion of fuels and fuels used as process input’ for those activities.

Table 1

Tiers for activity data (maximum permissible uncertainty for each tier)

Activity/source stream type	Parameter to which the uncertainty is applied	Tier 1	Tier 2	Tier 3	Tier 4
Combustion of fuels and fuels used as process input
Commercial standard fuels	Amount of fuel [t] or [Nm3]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Other gaseous and liquid fuels	Amount of fuel [t] or [Nm3]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Solid fuels	Amount of fuel [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Flaring	Amount of flare gas [Nm3]	± 17,5 %	± 12,5 %	± 7,5 %
Scrubbing: carbonate (Method A)	Amount carbonate consumed [t]	± 7,5 %
Scrubbing: gypsum (Method B)	Amount gypsum produced [t]	± 7,5 %
Scrubbing: urea	Amount urea consumed	± 7,5 %
Refining of mineral oil
Catalytic cracker regeneration (*1)	Uncertainty requirements apply separately for each emission source	± 10 %	± 7,5 %	± 5 %	± 2,5 %
Production of coke
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Metal ore roasting and sintering
Carbonate input and process residues	Carbonate input material and process residues [t]	± 5 %	± 2,5 %
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Production of iron and steel
Fuel as process input	Each mass flow into and from the installation [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Production of cement clinker
Kiln input based (Method A)	Each relevant kiln input [t]	± 7,5 %	± 5 %	± 2,5 %
Clinker output (Method B)	Clinker produced [t]	± 5 %	± 2,5 %
CKD	CKD or bypass dust [t]	n.a. (*2)	± 7,5 %
Non-carbonate carbon	Each raw material [t]	± 15 %	± 7,5 %
Production of lime and calcination of dolomite and magnesite
Carbonates and other process materials (Method A)	Each relevant kiln input [t]	± 7,5 %	± 5 %	± 2,5 %
Alkali earth oxide (Method B)	Lime produced [t]	± 5 %	± 2,5 %
Kiln dust (Method B)	Kiln dust [t]	n.a. (*2)	± 7,5 %
Manufacture of glass and mineral wool
Carbonates and other process materials (input)	Each carbonate raw material or additives associated with CO2 emissions [t]	± 2,5 %	± 1,5 %
Manufacture of ceramic products
Carbon inputs (Method A)	Each carbonate raw material or additive associated with CO2 emissions [t]	± 7,5 %	± 5 %	± 2,5 %
Alkali oxide (Method B)	Gross production including rejected products and cullet from the kilns and shipment [t]	± 7,5 %	± 5 %	± 2,5 %
Scrubbing	Dry CaCO3 consumed [t]	± 7,5 %
Production of pulp and paper
Make up chemicals	Amount of CaCO3 and Na2CO3 [t]	± 2,5 %	± 1,5 %
Production of carbon black
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Production of ammonia
Fuel as process input	Amount fuel used as process input [t] or [Nm3]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Production of hydrogen and synthesis gas
Fuel as process input	Amount fuel used as process input for hydrogen production [t] or [Nm3]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Production of bulk organic chemicals
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Production or processing of ferrous and non-ferrous metals, including secondary aluminium
Process emissions	Each input material or process residue used as input material in the process [t]	± 5 %	± 2,5 %
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
Primary aluminium production
Mass balance methodology	Each input and output material [t]	± 7,5 %	± 5 %	± 2,5 %	± 1,5 %
PFC emissions (slope method)	primary aluminium production in [t], anode effect minutes in [number anode effects/cell day] and [anode effect minutes/ occurrence]	± 2,5 %	± 1,5 %
PFC emissions (overvoltage method)	primary aluminium production in [t], anode effect overvoltage [mV] and current efficiency [-]	± 2,5 %	± 1,5 %

2.   DEFINITION OF TIERS FOR CALCULATION FACTORS FOR COMBUSTION EMISSIONS

Operators shall monitor CO2 emissions from all types of combustion processes taking place under all activities as listed in Annex I to Directive 2003/87/EC or included in the Union system under Article 24 of that Directive using the tier definitions laid down in this section. Where fuels or combustible materials which give rise to CO2 emissions are used as a process input, section 5 of this Annex shall apply. Where fuels form part of a mass balance in accordance with Article 25(1) of this Regulation, the tier definitions for mass balances in section 3 of this Annex apply.

For process emissions from related exhaust gas scrubbing tier definitions according to sections 4 and 5 of this Annex shall be used, as applicable.

2.1   Tiers for emission factors

Where a biomass fraction is determined for a mixed fuel or material, the tiers defined shall relate to the preliminary emission factor. For fossil fuels and materials the tiers shall relate to the emission factor.

Tier 1: The operator shall apply one of the following:

(a)	the standard factors listed in section 1 of Annex VI;

(b)	other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in section 1 of Annex VI.

Tier 2a: The operator shall apply country specific emission factors for the respective fuel or material in accordance with points (b) and (c) of Article 31(1) or values in accordance with point (d) of Article 31(1).

Tier 2b: The operator shall derive emission factors for the fuel based on one of the following established proxies, in combination with an empirical correlation as determined at least once per year in accordance with Articles 32 to 35 and 39:

(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 operator shall ensure that the correlation satisfies the requirements of good engineering practice and that it is applied only to values of the proxy which fall into the range for which it was established.

Tier 3: The operator shall apply one of the following:

(a)	determination of the emission factor in accordance with the relevant provisions of Articles 32 to 35;

(b)

the empirical correlation as specified for Tier 2b, where the operator demonstrates to the satisfaction of the competent authority that the uncertainty of the empirical correlation does not exceed 1/3 of the uncertainty value to which the operator has to adhere with regard to the activity data determination of the relevant fuel or material.

2.2   Tiers for net calorific value (NCV)

Tier 1: The operator shall apply one of the following:

(a)	the standard factors listed in section 1 of Annex VI;

(b)	other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in section 1 of Annex VI.

Tier 2a: The operator shall apply country specific factors for the respective fuel in accordance with point (b) or (c) of Article 31(1) or values in accordance with point (d) of Article 31(1).

Tier 2b: For commercially traded fuels the net calorific value as derived from the purchasing records for the respective fuel provided by the fuel supplier shall be used provided it has been derived based on accepted national or international standards.

Tier 3: The operator shall determine the net calorific value in accordance with Article 32 to 35.

2.3   Tiers for oxidation factors

Tier 1: The operator shall apply an oxidation factor of 1.

Tier 2: The operator shall apply oxidation factors for the respective fuel in accordance with point (b) or (c) of Article 31(1).

Tier 3: For fuels, the operator shall derive activity-specific factors based on the relevant carbon contents of ashes, effluents and other wastes and by-products, and other relevant incompletely oxidised gaseous forms of carbon emitted except CO. Composition data shall be determined in accordance with Article 32 to 35.

2.4   Tiers for biomass fraction

Tier 1: The operator shall apply an applicable value published by the competent authority or the Commission, or values in accordance with Article 31(1).

Tier 2: The operator shall apply an estimation method approved in accordance with the second subparagraph of Article 39(2).

Tier 3: The operator shall apply analyses in accordance with the first sub-paragraph of Article 39 (2), and in accordance with Articles 32 to 35.

Where an operator assumes a fossil fraction of 100 % in accordance with Article 39(1), no tier shall be assigned for the biomass fraction.

3.   DEFINITION OF TIERS FOR CALCULATION FACTORS FOR MASS BALANCES

Where an operator uses a mass balance in accordance with Article 25, it shall use the tier definitions of this section.

3.1   Tiers for carbon content

The operator shall apply one of the tiers listed in this point. For deriving the carbon content from an emission factor, the operator shall use the following equations:

(a)	for emission factors expressed as t CO2/TJ	:	C = (EF × NCV) / f
(b)	for emission factors expressed as t CO2/t	:	C = EF / f

In those formulae, C is the carbon content expressed as fraction (tonne carbon per tonne product), EF is the emission factor, NCV is the net calorific value, and f is the factor laid down in Article 36(3).

Where a biomass fraction is determined for a mixed fuel or material, the tiers defined shall relate to the total carbon content. The biomass fraction of the carbon shall be determined using the tiers defined in section 2.4 of this Annex.

Tier 1: The operator shall apply one of the following:

(a)	the carbon content derived from standard factors listed in Annex VI sections 1 and 2;

(b)	other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in Annex VI sections 1 and 2.

Tier 2a: The operator shall derive the carbon content from country specific emission factors for the respective fuel or material in accordance with point (b) or (c) of Article 31(1) or values in accordance with point (d) of Article 31(1).

Tier 2b: The operator shall derive the carbon content from emission factors for the fuel based on one of the following established proxies in combination with an empirical correlation as determined at least once per year in accordance with Articles 32 to 35:

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

(b)	net calorific value for specific coals types.

The operator shall ensure that the correlation satisfies the requirements of good engineering practice and that it is applied only to values of the proxy which fall into the range for which it was established.

Tier 3: The operator shall apply one of the following:

(a)	determination of the carbon content in accordance with the relevant provisions of Articles 32 to 35;

(b)

the empirical correlation as specified for Tier 2b, where the operator demonstrates to the satisfaction of the competent authority that the uncertainty of the empirical correlation does not exceed 1/3 of the uncertainty value to which the operator has to adhere with regard to the activity data determination of the relevant fuel or material.

3.2   Tiers for net calorific values

The tiers defined in section 2.2 of this Annex shall be used.

3.3   Tiers for biomass fraction

The tiers defined in section 2.4 of this Annex shall be used.

4.   DEFINITION OF TIERS FOR THE CALCULATION FACTORS FOR PROCESS EMISSIONS FROM CARBONATE DECOMPOSITION

For all process emissions, where they are monitored using the standard methodology in accordance with Article 24(2), the following tier definitions for the emission factor and the conversion factor shall be applied in the case of:

(a)	Method A: Input based, the emission factor and activity data related to the amount of material input into the process.

(b)	Method B: Output based, the emission factor and activity data related to the amount of output from the process.

4.1   Tiers for the emission factor using Method A:

Tier 1: The operator shall apply one of the following:

(a)	the standard factors listed in Annex VI section 2 Table 2;

(b)	other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in Annex VI.

Tier 2: The operator shall apply a country specific emission factor in accordance with point (b) or (c) of Art. 31(1), or values in accordance with point (d) of Article 31(1).

Tier 3: The operator shall determine the emission factor in accordance with Articles 32 to 35. Stoichiometric ratios as listed in section 2 of Annex VI shall be used to convert composition data into emission factors, where relevant.

4.2   Tiers for the conversion factor using Method A:

Tier 1: A conversion factor of 1 shall be used.

Tier 2: Carbonates and other carbon leaving the process shall be considered by means of a conversion factor with a value between 0 and 1. The operator may assume complete conversion for one or several inputs and attribute unconverted materials or other carbon to the remaining inputs. The additional determination of relevant chemical parameters of the products shall be carried out in accordance with Articles 32 to 35.

4.3   Tiers for the emission factor using Method B:

Tier 1: The operator shall apply one of the following:

(a)	the standard factors listed in Annex VI section 2 Table 3.

(b)	other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in Annex VI.

Tier 2: The operator shall apply a country specific emission factor in accordance with point (b) or (c) of Article 31(1), or values in accordance with point (d) of Article 31(1).

Tier 3: The operator shall determine the emission factor in accordance with Articles 32 to 35. Stoichiometric ratios referred to in Annex VI section 2 Table 3 shall be used to convert composition data into emission factors assuming that all of the relevant metal oxides have been derived from respective carbonates. For this purpose the operator shall take into account at least CaO and MgO, and shall provide evidence to the competent authority as to which further metal oxides relate to carbonates in the raw materials.

4.4   Tiers for the conversion factor using Method B:

Tier 1: A conversion factor of 1 shall be used.

Tier 2: The amount of non-carbonate compounds of the relevant metals in the raw materials, including return dust or fly ash or other already calcined materials, shall be reflected by means of conversion factors with a value between 0 and 1 with a value of 1 corresponding to a full conversion of raw material carbonates into oxides. The additional determination of relevant chemical parameters of the process inputs shall be carried out in accordance with Articles 32 to 35.

5.   DEFINITION OF TIERS FOR CALCULATION FACTORS FOR CO2 PROCESS EMISSIONS FROM OTHER MATERIALS THAN CARBONATES

Process materials giving raise to CO2 emissions, including urea, coke, graphite and other non-carbonate carbon containing materials, shall be monitored using an input-based approach according to this section, unless included in a mass balance.

5.1   Tiers for emission factors

The tiers defined in section 2.1 of this Annex shall be used.

5.2   Tiers for net calorific value (NCV)

If the process material contains combustible carbon, the operator shall report the NCV value. The tiers defined in section 2.2 of this Annex shall be used.

5.3   Tiers for conversion / oxidation factors

If the process material contains combustible carbon, the operator shall apply an oxidation factor. For this purpose the tiers defined in section 2.3 of this Annex shall be used.

In all other cases the operator shall apply a conversion factor. For this purpose the following tier definitions shall apply:

Tier 1: A conversion factor of 1 shall be used.

Tier 2: Carbon leaving the process shall be considered by means of a conversion factor with a value between 0 and 1. The operator may assume complete conversion for one or several inputs and attribute unconverted materials or other carbon to the remaining inputs. The additional determination of relevant chemical parameters of the products shall be carried out in accordance with Articles 32 to 35.

5.4   Tiers for biomass fraction

The tiers defined in section 2.4 of this Annex shall be used.

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(*1)  For monitoring emissions from catalytic cracker regeneration (other catalyst regeneration and flexi-cokers) in mineral oil refineries, the required uncertainty is related to the total uncertainty of all emissions from that source.

(*2)  Amount [t] of CKD or bypass dust (where relevant) leaving the kiln system over a reporting period estimated using industry best practice guidelines.

ANNEX III

Monitoring methodologies for aviation (Article 53 and Article 57)

1.   CALCULATION METHODOLOGIES FOR THE DETERMINATION OF GHGS IN THE AVIATION SECTOR

Method A:

The operator shall use the following formula:

Actual fuel consumption for each flight [t] = Amount of fuel contained in aircraft tanks once fuel uplift for the flight is complete [t] – Amount of fuel contained in aircraft tanks once fuel uplift for subsequent flight is complete [t] + Fuel uplift for that subsequent flight [t]

Where there is no fuel uplift for the flight or subsequent flight, the amount of fuel contained in aircraft tanks shall be determined at block-off for the flight or subsequent flight. In the exceptional case that an aircraft performs activities other than a flight, including undergoing major maintenance involving the emptying of the tanks, after the flight for which fuel consumption is being monitored, the aircraft operator may substitute the quantity ‘Amount of fuel contained in aircraft tanks once fuel uplift for subsequent flight is complete + Fuel uplift for that subsequent flight’ with the ‘Amount of fuel remaining in tanks at the start of the subsequent activity of the aircraft’, as recorded by technical logs.

Method B:

The operator shall use the following formula:

Actual fuel consumption for each flight [t] = Amount of fuel remaining in aircraft tanks at block-on at the end of the previous flight [t] + Fuel uplift for the flight [t] - Amount of fuel contained in tanks at block-on at the end of the flight [t]

The moment of block-on may be considered equivalent to the moment of engine shut down. Where an aircraft does not perform a flight previous to the flight for which fuel consumption is being monitored, the aircraft operator may substitute the quantity ‘Amount of fuel remaining in aircraft tanks at block-on at the end of the previous flight’ with the ‘Amount of fuel remaining in aircraft tanks at the end of the previous activity of the aircraft’, as recorded by technical logs.

2.   EMISSION FACTORS FOR STANDARD FUELS

Table 1

Aviation fuel CO2 emission factors

Fuel	Emission factor (t CO2/t fuel)
Aviation gasoline (AvGas)	3,10
Jet gasoline (Jet B)	3,10
Jet kerosene (Jet A1 or Jet A)	3,15

3.   CALCULATION OF GREAT CIRCLE DISTANCE

Distance [km] = Great Circle Distance [km] + 95 km

The Great Circle Distance shall be the shortest distance between any two points on the surface of the Earth, which shall be approximated using the system referred to in Article 3.7.1.1 of Annex 15 to the Chicago Convention (WGS 84).

The latitude and longitude of aerodromes shall be taken either from aerodrome location data published in Aeronautical Information Publications (AIP) in compliance with Annex 15 to the Chicago Convention or from a source using AIP data.

Distances calculated by software or by a third party may also be used, provided that the calculation methodology is based on the formula set out in this section, AIP data and WGS 84 requirements.

ANNEX IV

Activity-specific monitoring methodologies related to installations (Article 20(2))

1.   SPECIFIC MONITORING RULES FOR EMISSIONS FROM COMBUSTION PROCESSES

A.   Scope

Operators shall monitor CO2 emissions from all types of combustion processes taking place under all activities as listed in Annex I to Directive 2003/87/EC or included in the Union system under Article 24 of that Directive including the related scrubbing processes using the rules laid down in this Annex. Any emissions from fuels used as process input shall be treated like combustion emissions with regard to monitoring and reporting methodologies, without prejudice to other classifications applied to emissions.

The operator shall not monitor and report emissions from internal combustion engines for transportation purposes. The operator shall assign all emissions from the combustion of fuels at the installation to the installation, regardless of exports of heat or electricity to other installations. The operator shall not assign emissions associated with the production of heat or electricity that is imported from other installations to the importing installation.

The operator shall include at least the following emission sources: boilers, burners, turbines, heaters, furnaces, incinerators, calciners, kilns, ovens, dryers, engines, fuel cells, chemical looping combustion units, flares, thermal or catalytic post-combustion units, and scrubbers (process emissions) and any other equipment or machinery that uses fuel, excluding equipment or machinery with combustion engines that are used for transportation purposes.

B.   Specific monitoring rules

The emissions from combustion processes shall be calculated in accordance with Article 24(1), unless the fuels are included in a mass balance in accordance with Article 25. The tiers defined in section 2 of Annex II shall apply. In addition, process emissions from flue gas scrubbing shall be monitored using the provisions laid down in subsection C.

For emissions from flares special requirements shall apply, as laid down in subsection D of this section.

Combustion processes taking place in gas processing terminals may be monitored using a mass balance in accordance with Article 25.

C.   Flue gas scrubbing

C.1   Desulphurisation

Process CO2 emissions from the use of carbonate for acid gas scrubbing from the flue gas stream shall be calculated in accordance with Article 24(2) on the basis of carbonate consumed, Method A as follows, or gypsum produced, Method B as follows. The following applies by way of derogation from section 4 of Annex II.

Method A: Emission factor

Tier 1: The emission factor shall be determined from stoichiometric ratios as laid down in section 2 of Annex VI. The determination of the amount of CaCO3 and MgCO3 or other carbonates in the relevant input material shall be carried out using industry best practice guidelines.

Method B: Emission factor

Tier 1: The emission factor shall be the stoichiometric ratio of dry gypsum (CaSO4 × 2H2O) to CO2 emitted: 0,2558 t CO2/t gypsum.

Conversion Factor:

Tier 1: A conversion factor of 1 shall be used.

C.2   De-NOx

By way of derogation from section 5 of Annex II, process CO2 emissions from the use of urea for scrubbing of the flue gas stream shall be calculated in accordance with Article 24(2) applying the following tiers.

Emission factor:

Tier 1: The determination of the amount of urea in the relevant input material shall be carried out using industry best practice guidelines. The emission factor shall be determined using a stoichiometric ratio of 0,7328 t CO2/t urea.

Conversion Factor:

Only tier 1 shall be applicable.

D.   Flares

When calculating emissions from flares the operator shall include routine flaring and operational flaring (trips, start-up and shutdown as well as emergency relieves). The operator shall also include inherent CO2 in accordance with Article 48.

By way of derogation from section 2.1 of Annex II, tiers 1 and 2b for the emission factor shall be defined as follows:

Tier 1: The operator shall use a reference emission factor of 0,00393 t CO2/Nm3 derived from the combustion of pure ethane used as a conservative proxy for flare gases.

Tier 2b: Installation-specific emission factors shall be 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.

By way of derogation from section 2.3 of Annex II, only tiers 1 and 2 shall be applied for the oxidation factor in the case of flares.

2.   REFINING OF MINERAL OIL AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall monitor and report all CO2 emissions from combustion and production processes as occurring in refineries.

The operator shall include at least the following potential sources of CO2 emissions: boilers, process heaters/treaters, internal combustion engines/turbines, catalytic and thermal oxidisers, coke calcining kilns, firewater pumps, emergency/standby generators, flares, incinerators, crackers, hydrogen production units, Claus process units, catalyst regeneration (from catalytic cracking and other catalytic processes) and cokers (flexi-coking, delayed coking).

B.   Specific monitoring rules

The monitoring of mineral oil refining activities shall be carried out in accordance with section 1 of this Annex for combustion emissions including flue gas scrubbing. The operator may choose to use the mass balance methodology in accordance with Article 25 for the whole refinery or individual process units such as heavy oil gasification or calcinations plants. Where combinations of standard methodology and mass balance are used, the operator shall provide evidence to the competent authority demonstrating the completeness of emissions covered, and that no double counting of emissions occurs.

Emissions from dedicated hydrogen production units shall be monitored in accordance with section 19 of this Annex.

By way of derogation from Article 24 and 25, emissions from catalytic cracker regeneration, other catalyst regeneration and flexi-cokers shall be monitored using a mass balance, taking into account the state of the input air and the flue gas. All CO in the flue gas shall be accounted for as CO2, applying the mass relation: t CO2 = t CO * 1,571. The analysis of input air and flue gases and the choice of tiers shall be in accordance with the provisions of Articles 32 to 35. The specific calculation methodology shall be approved by the competent authority.

3.   PRODUCTION OF COKE AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential sources of CO2 emissions: raw materials (including coal or petroleum coke), conventional fuels (including natural gas), process gases (including blast furnace gas – BFG), other fuels and waste gas scrubbing.

B.   Specific monitoring rules

For the monitoring of emissions from the production of coke, the operator may choose to use a mass balance in accordance with Article 25 and section 3 of Annex II, or the standard methodology in accordance with Article 24 and sections 2 and 4 of Annex II.

4.   METAL ORE ROASTING AND SINTERING AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential sources of CO2 emissions: raw materials (calcination of limestone, dolomite and carbonatic iron ores, including FeCO3), conventional fuels (including natural gas and coke/coke breeze), process gases (including coke oven gas – COG, and blast furnace gas – BFG), process residues used as input material including filtered dust from the sintering plant, the converter and the blast furnace, other fuels and flue gas scrubbing.

B.   Specific monitoring rules

For the monitoring of emissions from metal ore roasting, sintering or pelletisation, the operator may choose to use a mass balance in accordance with Article 25 and section 3 of Annex II or the standard methodology in accordance with Article 24 and sections 2, 4 and 5 of Annex II.

5.   PRODUCTION OF PIG IRON AND STEEL AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential sources of CO2 emissions: raw materials (calcination of limestone, dolomite and carbonatic iron ores, including FeCO3), conventional fuels (natural gas, coal and coke), reducing agents (including coke, coal and plastics), process gases (coke oven gas – COG, blast furnace gas – BFG and basic oxygen furnace gas – BOFG), consumption of graphite electrodes, other fuels and waste gas scrubbing.

B.   Specific monitoring rules

For the monitoring of emissions from production of pig iron and steel, the operator may choose to use a mass balance in accordance with Article 25 and section 3 of Annex II, or the standard methodology in accordance with Article 24 and sections 2 and 4 of Annex II, at least for a part of the source streams, avoiding any gaps or double counting of emissions.

By way of derogation from section 3.1 of Annex II, tier 3 for the carbon content is defined as follows:

Tier 3: The operator shall derive the carbon content of input or output stream following Articles 32 to 35 in respect to the representative sampling of fuels, products and by-products, the determination of their carbon contents and biomass fraction. The operator shall base the carbon content of products or semi-finished products on annual analyses following Articles 32 to 35 or derive the carbon content from mid-range composition values as specified by relevant international or national standards.

6.   PRODUCTION OR PROCESSING OF FERROUS AND NON-FERROUS METALS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall not apply the provisions in this section for the monitoring and reporting of CO2 emissions from the production of pig iron and steel and primary aluminium.

The operator shall consider at least the following potential emission sources for CO2 emissions: conventional fuels; alternative fuels including plastics granulated material from post shredder plants; reducing agents including coke, graphite electrodes; raw materials including limestone and dolomite; carbon containing metal ores and concentrates; and secondary feed materials.

B.   Specific monitoring rules

Where carbon stemming from fuels or input materials used at this installation remains in the products or other outputs of the production, the operator shall use a mass balance in accordance with Article 25 and section 3 of Annex II. Where this is not the case the operator shall calculate combustion and process emission separately using the standard methodology in accordance with Article 24 and sections 2 and 4 of Annex II.

Where a mass balance is used, the operator may choose to include emissions from combustion processes in the mass balance or to use the standard methodology in accordance with Article 24 and section 1 of this Annex for a part of the source streams, avoiding any gaps or double counting of emissions.

7.   CO2 EMISSIONS FROM PRODUCTION OR PROCESSING OF PRIMARY ALUMINIUM AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall apply the provisions of this section to the monitoring and reporting of CO2 emissions from the production of electrodes for primary aluminium smelting, including stand-alone plants for the production of such electrodes, and the consumption of electrodes during electrolysis.

The operator shall consider at least the following potential sources for CO2 emissions: fuels for the production of heat or steam, electrode production, reduction of Al2O3 during electrolysis which is related to electrode consumption, and use of soda ash or other carbonates for waste gas scrubbing.

The associated emissions of perfluorocarbons – PFCs, resulting from anode effects, including fugitive emissions, shall be monitored in accordance with section 8 of this Annex.

B.   Specific monitoring rules

The operator shall determine CO2 emissions from the production or processing of primary aluminium using the mass balance methodology in accordance with Article 25. The mass balance methodology shall consider all carbon in inputs, stocks, products and other exports from the mixing, forming, baking and recycling of electrodes as well as from electrode consumption in electrolysis. Where pre-baked anodes are used, either separate mass balances for production and consumption may be applied, or one common mass balance taking into account both production and consumption of electrodes. In the case of Søderberg cells, the operator shall use one common mass balance.

For emissions from combustion processes the operator may choose to include them in the mass balance or to use the standard methodology in accordance with Article 24 and section 1 of this Annex at least for a part of the source streams, avoiding any gaps or double counting of emissions.

8.   PFC EMISSIONS FROM PRODUCTION OR PROCESSING OF PRIMARY ALUMINIUM AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall apply the following for emissions of perfluorocarbons (PFCs) resulting from anode effects including fugitive emissions of PFCs. For associated CO2 emissions, including emissions from electrode production, the operator shall apply section 7 of this Annex. The operator shall furthermore calculate PFC emissions not related to anode effects based on estimation methods in accordance with industry best practice, and any guidelines published by the Commission for this purpose.

B.   Determination of PFC emissions

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

The collection efficiency shall be measured when the installation-specific emission factors are determined. For its determination the most recent version of the guidance mentioned under Tier 3 of section 4.4.2.4 of the 2006 IPCC Guidelines shall be used.

The operator shall calculate emissions of CF4 and C2F6 emitted through a duct or stack using one of the following methods:

(a)	Method A where the anode effect minutes per cell-day are recorded;

(b)	Method B where the anode effect overvoltage is recorded.

Calculation Method A – Slope Method:

The operator shall use the following equations for determining PFC emissions:

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

C2F6 emissions [t] = CF4 emissions × FC2F6

Where:

AEM= Anode effect minutes / cell-day;

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

PrAl = Annual production of primary Aluminium [t];

FC2F6 = Weight fraction of C2F6 (t C2F6 / t CF4).

The anode effect minutes per cell-day shall express 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

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 / cell-day. The emission factor (weight fraction FC2F6) of C2F6 expresses the amount [t] of C2F6 emitted proportionate to the amount [t] of CF4 emitted.

Tier 1: The operator shall use technology-specific emission factors from Table 1 of this section of Annex IV.

Tier 2: The operator shall use installation-specific emission factors for CF4 and C2F6 established through continuous or intermittent field measurements. For the determination of those emission factors the operator shall use the most recent version of the guidance mentioned under Tier 3 of section 4.4.2.4 of the 2006 IPCC Guidelines (1). The emission factor shall also take into account emissions related to non-anode effects. The operator shall determine each emission factor with a maximum uncertainty of ± 15 %.

The operator shall determine the emission factors 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 1

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

Technology	Emission factor for CF4 (SEFCF4) [(kg CF4/t Al) / (AE-Mins/cell-day)]	Emission factor for C2F6 (FC2F6) [t C2F6/ t CF4]
Centre Worked Prebake (CWPB)	0,143	0,121
Vertical Stud Søderberg (VSS)	0,092	0,053

Calculation Method B – Overvoltage Method:

Where the anode effect overvoltage is measured, the operator shall use the following equations for the determination of PFC emissions:

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

C2F6 emissions [t] = CF4 emissions × FCF2F6

Where:

OVC= Overvoltage coefficient (‘emission factor’) expressed as kg CF4 per tonne of aluminium produced per mV overvoltage;

AEO= 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= Average current efficiency of aluminium production [%];

PrAl = Annual production of primary Aluminium [t];

FCF2F6 = 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 [%].

Emission factor: The emission factor for CF4 (‘overvoltage coefficient’ OVC) shall express the amount [kg] of CF4 emitted per tonne of aluminium produced per millivolt overvoltage [mV]. The emission factor of C2F6 (weight fraction FC2F6) shall express the amount [t] of C2F6 emitted proportionate to the amount [t] of CF4 emitted.

Tier 1:: The operator shall apply technology-specific emission factors from Table 2 of this section of Annex IV.

Tier 2: The operator shall use installation-specific emission factors 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, the operator shall use the most recent version of the guidance mentioned under Tier 3 of section 4.4.2.4 of the 2006 IPCC Guidelines. The operator shall determine the emission factors with a maximum uncertainty of ± 15 % each.

The operator shall determine the emission factors 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 overvoltage activity data.

Technology	Emission factor for CF4 [(kg CF4/t Al) / mV]	Emission factor for C2F6 [t C2F6/ t CF4]
Centre Worked Prebake (CWPB)	1,16	0,121
Vertical Stud Søderberg (VSS)	N.A.	0,053

C.   Determination of CO2(e) emissions

The operator shall calculate CO2(e) emissions from CF4 and C2F6 emissions as follows, using the global warming potentials listed in Annex VI section 3 Table 6:

PFC emissions [t CO2(e)] = CF4 emissions [t] × GWPCF4 + C2F6 emissions [t] × GWPC2F6

9.   PRODUCTION OF CEMENT CLINKER AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential sources of CO2 emissions: calcination of limestone in the raw materials, conventional fossil kiln fuels, alternative fossil-based kiln fuels and raw materials, biomass kiln fuels (biomass wastes), non-kiln fuels, organic carbon content of limestone and shales and raw materials used for waste gas scrubbing.

B.   Specific monitoring rules

Emissions from combustion shall be monitored in accordance with section 1 of this Annex. Process emissions from raw meal components shall be monitored in accordance with section 4 of Annex II based on the carbonate content of the process input (calculation Method A) or on the amount of clinker produced (calculation Method B). In case of Method A, carbonates to be taken into account shall at least include CaCO3, MgCO3 and FeCO3. In case of Method B, the operator shall take into account at least CaO and MgO, and shall provide evidence to the competent authority as to which extent further carbon sources have to be taken into account.

CO2 emissions related to dust removed from the process and organic carbon in the raw materials shall be added in accordance with subsections C and D of this section of Annex IV.

Calculation Method A: Kiln Input Based

Where cement kiln dust (CKD) and bypass dust leave the kiln system the operator shall not consider the related raw material as process input, but calculate emissions from CKD in accordance with subsection C.

Unless the raw meal is characterised, the operator shall apply the uncertainty requirements for activity data separately to each of the relevant carbon-bearing kiln inputs, 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.

Calculation Method B: Clinker Output Based

The operator shall determine activity data as the clinker production [t] over the reporting period in one of the following ways:

(a)	by direct weighing of clinker;

(b)

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: clinker produced [t] = ((cement deliveries [t] – cement stock variation [t]) × clinker / cement ratio [t clinker / t cement]) – (clinker supplied [t]) + (clinker dispatched [t]) – (clinker stock variation [t]).

The operator shall either derive the clinker / cement ratio for each of the different cement products based on the provisions of Articles 32 to 35 or calculate the 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.

By way of derogation from section 4 of Annex II, tier 1 for the emission factor shall be defined as follows:

Tier 1: The operator shall apply an emission factor of 0,525 t CO2/t clinker.

C.   Emissions Related to Discarded Dust

The operator shall add CO2 emissions, from bypass dust or cement kiln dust (CKD) leaving the kiln system, corrected for a partial calcination ratio of CKD calculated as process emissions in accordance with Article 24(2). By way of derogation from section 4 of Annex II, tiers 1 and 2 for the emission factor shall be defined as follows:

Tier 1: The operator shall apply an emission factor of 0,525 t CO2/t dust.

Tier 2: The operator shall determine the emission factor (EF) at least once annually following Articles 32 to 35 and using the following formula:

Where:

EFCKD = Emission factor of partially calcined cement kiln dust [t CO2/t CKD];

EFCli = Installation-specific emission factor of clinker [t CO2/t clinker];

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

Tier 3 for the emission factor is not applicable.

D.   Emissions from non-carbonate carbon in raw meal

The operator shall determine the emissions from non-carbonate carbon at least from limestone, shale or alternative raw materials (for example, fly ash) used in the raw meal in the kiln in accordance with Article 24(2).

The following tier definitions for the emission factor shall apply:

Tier 1: The content of non-carbonate carbon in the relevant raw material shall be estimated using industry best practice guidelines.

Tier 2: The content of non-carbonate carbon in the relevant raw material shall be determined at least annually following the provisions of Article 32 to 35.

The following tier definitions for the conversion factor shall apply:

Tier 1: A conversion factor of 1 shall be applied.

Tier 2: The conversion factor shall be calculated applying industry best practice.

10.   PRODUCTION OF LIME OR CALCINATION OF DOLOMITE OR MAGNESITE AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential sources of CO2 emissions: calcination of limestone, dolomite or magnesite in the raw materials, conventional fossil kiln fuels, alternative fossil-based kiln fuels and raw materials, biomass kiln fuels (biomass wastes) and other fuels.

Where the burnt lime and the CO2 stemming from the limestone are used for purification processes, such that approximately the same amount of CO2 is bound again, the decomposition of carbonates as well as the purification process shall not be required to be included separately in the monitoring plan of the installation.

B.   Specific monitoring rules

Emissions from combustion shall be monitored in accordance with section 1 of this Annex. Process emissions from raw materials shall be monitored in accordance with section 4 and section 5 of Annex II. Carbonates of calcium and magnesium shall be always taken into account. Other carbonates and organic carbon in the raw material shall be taken into account, whenever they are relevant for emission calculation.

For the input based methodology, carbonate content values shall be adjusted for the respective moisture and gangue content of the material. In the case of magnesia production, other magnesium bearing minerals than carbonates must be taken into account, as appropriate.

Double counting or omissions resulting from returned or by-pass material must be avoided. When applying Method B, lime kiln dust shall be considered a separate source stream where relevant.

11.   MANUFACTURE OF GLASS, GLASS FIBRE OR MINERAL WOOL INSULATION MATERIAL AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall apply the provisions in this section also to installations for the production of water glass and stone/rock wool.

The operator shall include at least the following potential sources of CO2 emissions: decomposition of alkali- and alkali earth carbonates as the result of melting the raw material, conventional fossil fuels, alternative fossil-based fuels and raw materials, biomass fuels (biomass wastes), other fuels, carbon containing additives including coke, coal dust and graphite, post-combustion of flue gases and flue gas scrubbing.

B.   Specific monitoring rules

Emissions from combustion, including flue gas scrubbing, shall be monitored in accordance with section 1 of this Annex. Process emissions from raw materials shall be monitored in accordance with section 4 of Annex II. Carbonates to be taken into account include at least CaCO3, MgCO3, Na2CO3, NaHCO3, BaCO3, Li2CO3, K2CO3, and SrCO3. Only Method A shall be used. Emissions from other process materials including coke, graphite and coal dust shall be monitored in accordance with section 5 of Annex II.

By way of derogation from section 4 of Annex II, the following tier definitions for the emission factor shall apply:

Tier 1: Stoichiometric ratios as listed in section 2 of Annex VI shall be used. The purity of relevant input materials shall be determined by means of industry best practice.

Tier 2: The determination of the amount of relevant carbonates in each relevant input material shall be carried out in accordance with Articles 32 to 35.

For the conversion factor, only tier 1 shall be applicable.

12.   MANUFACTURE OF CERAMIC PRODUCTS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential sources of CO2 emissions: kiln fuels, calcination of limestone/dolomite and other carbonates in the raw material, limestone and other carbonates for reducing air pollutants and other flue gas cleaning, fossil/biomass additives used to induce porosity including polystyrol, residues from paper production or sawdust, fossil organic material in the clay and other raw materials.

B.   Specific monitoring rules

Emissions from combustion including flue gas scrubbing shall be monitored in accordance with section 1 of this Annex. Process emissions from raw meal components and additives shall be monitored in accordance with sections 4 and 5 of Annex II. For ceramics based on purified or synthetic clays the operator may use either Method A or Method B. For ceramic products based on unprocessed clays and whenever clays or additives with significant organic content are used, the operator shall use Method A. Carbonates of calcium shall be always taken into account. Other carbonates and organic carbon in the raw material shall be taken into account, where they are relevant for emission calculation.

Activity data for input materials for Method A may be determined by a suitable back-calculation based on industry best practice and approved by the competent authority. Such back-calculation shall take into account what metering is available for dried green products or fired products, and appropriate data sources for moisture of clay and additives and annealing loss (loss on ignition) of the materials involved.

By way of derogation from section 4 of Annex II, the following tier definitions for emission factors for process emissions of raw materials containing carbonates shall apply:

Method A (Input based):

Tier 1: A conservative value of 0,2 tonnes CaCO3 (corresponding to 0,08794 tonnes of CO2) per tonne of dry clay shall be applied for the calculation of the emission factor instead of results of analyses. All inorganic and organic carbon in the clay material shall be considered as included in this value. Additives shall be considered as not included in this value.

Tier 2: An emission factor for each source stream shall be derived and updated at least once per year using industry best practice reflecting site-specific conditions and the product mix of the installation.

Tier 3: The determination of the composition of the relevant raw materials shall be carried out in accordance with Articles 32 to 35. Stoichiometric ratios as listed in section 2 of Annex VI shall be used to convert composition data into emission factors, where relevant.

Method B (Output based):

Tier 1: A conservative value of 0,123 tonnes of CaO (corresponding to 0,09642 tonnes of CO2) per tonne of product shall be applied for the calculation of the emission factor instead of the results of analyses. All inorganic and organic carbon in the clay material shall be considered as included in this value. Additives shall be considered as not included in this value.

Tier 2: An emission factor shall be derived and updated at least once per year using industry best practice reflecting site-specific conditions and the product mix of the installation.

Tier 3: The determination of the composition of the products shall be carried out in accordance with Articles 32 to 35. Stoichiometric ratios referred to in Annex VI section 2 Table 3 shall be used to convert composition data into emission factors assuming that all of the relevant metal oxides have been derived from respective carbonates, where relevant.

By way of derogation from section 1 of this Annex, for the scrubbing of flue gases the following tier for the emission factor shall apply:

Tier 1: The operator shall apply the stoichiometric ratio of CaCO3 as shown in section 2 of Annex VI.

For scrubbing, no other tier and no conversion factor shall be used. Double counting from used limestone recycled as raw material in the same installation shall be avoided.

13.   PRODUCTION OF GYPSUM PRODUCTS AND PLASTER BOARDS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least CO2 emissions from all types of combustion activities.

B.   Specific monitoring rules

Emissions from combustion shall be monitored in accordance with section 1 of this Annex.

14.   PULP AND PAPER PRODUCTION AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential sources of CO2 emissions: boilers, gas turbines, and other combustion devices producing steam or power, recovery boilers and other devices burning spent pulping liquors, incinerators, lime kilns and calciners, waste gas scrubbing and fuel-fired dryers (such as infrared dryers).

B.   Specific monitoring rules

The monitoring of emissions from combustion including flue gas scrubbing shall be carried out in accordance with section 1 of this Annex.

Process emissions from raw materials used as make-up chemicals, including at least limestone or soda ash, shall be monitored by Method A in accordance with section 4 of Annex II. CO2 emissions from the recovery of limestone sludge in pulp production shall be assumed to be recycled biomass CO2. Only the amount of CO2 proportional to the input from make-up chemicals shall be assumed to give rise to fossil CO2 emissions.

For emissions from make-up chemicals, the following tier definitions for the emission factor shall apply:

Tier 1: Stoichiometric ratios as listed in section 2 of Annex VI shall be used. The purity of relevant input materials shall be determined by means of industry best practice. The derived values shall be adjusted in accordance with the moisture and gangue content of the applied carbonate materials.

Tier 2: The determination of the amount of relevant carbonates in each relevant input material shall be carried out in accordance with Articles 32 to 35. Stoichiometric ratios as listed in section 2 of Annex VI shall be used to convert composition data into emission factors, where relevant.

For the conversion factor, only tier 1 shall be applicable.

15.   PRODUCTION OF CARBON BLACK AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least all fuels for combustion and all fuels used as process material as sources for CO2 emissions.

B.   Specific monitoring rules

The monitoring of emissions from carbon black production may be monitored either as a combustion process, including flue gas scrubbing, in accordance with section 1 of this Annex or using a mass balance in accordance with Article 25 and section 3 of Annex II.

16.   DETERMINATION OF NITROUS OXIDE (N2O) EMISSIONS FROM NITRIC ACID, ADIPIC ACID, CAPROLACTAM, GLYOXAL AND GLYOXYLIC ACID PRODUCTION AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

Each operator shall consider for each activity from which N2O emissions result, all sources emitting N2O from production processes, including where N2O emissions from production are channelled through any abatement equipment. This includes any of the following:

(a)	nitric acid production – N2O emissions from the catalytic oxidation of ammonia and/or from the NOx/N2O abatement units;

(b)	adipic acid production – N2O emissions including from the oxidation reaction, any direct process venting and/or any emissions control equipment;

(c)	glyoxal and glyoxylic acid production – N2O emissions including from the process reactions, any direct process venting and/or any emissions control equipment;

(d)	caprolactam production – N2O emissions including from the process reactions, any direct process venting and/or any emissions control equipment.

These provisions shall not apply to any N2O emissions from the combustion of fuels.

B.   Determination of N2O emissions

B.1.   Annual N2O emissions

The operator shall monitor emissions of N2O from nitric acid production using continuous emissions measurement. The operator shall monitor emissions of N2O from adipic acid, caprolactam, glyoxal and glyoxylic acid production using a measurement-based methodology for abated emissions and a calculation-based method (based on a mass balance methodology) for temporary occurrences of unabated emissions.

For each emission source where continuous emissions measurement is applied, the operator shall consider the total annual emissions to be the sum of all hourly emissions using equation 1 given in section 3 of Annex VIII.

B.2.   Hourly N2O emissions

The operator shall calculate annual average hourly N2O emissions for each source where continuous emission measurement is applied using equation 2 given in section 3 of Annex VIII.

The operator shall determine hourly N2O concentrations in the flue gas from each emission source using a measurement-based methodology at a representative point, after the NOx/N2O abatement equipment, where abatement is used. The operator shall apply techniques capable of measuring N2O concentrations of all emission sources during both abated and unabated conditions. Where uncertainties increase during such periods, the operator shall take them into account in the uncertainty assessment.

The operator shall adjust all measurements to a dry gas basis where required and report them consistently.

B.3.   Determination of flue gas flow

The operator shall use the methods for monitoring flue gas flow set out in Article 43(5) of this Regulation for measuring the flue gas flow for N2O emissions monitoring. For nitric acid production, the operator shall apply the method in accordance with point (a) of Article 43(5) unless it is technically not feasible. In that case and upon approval by the competent authority, the operator shall apply an alternative method, including by a mass balance methodology 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)

Where:

Vair = Total input air flow in Nm3/h at standard conditions;

O2, air = Volume fraction of O2 in dry air [= 0,2095];

O2, flue gas = Volume fraction of O2 in the flue gas.

The Vair shall be calculated as the sum of all air flows entering the nitric acid production unit.

The operator shall apply the following formula, unless stated otherwise in its monitoring plan:

Vair = Vprim + Vsec + Vseal

Where:

Vprim = Primary input air flow in Nm3/h at standard conditions;

Vsec = Secondary input air flow in Nm3/h at standard conditions;

Vseal = Seal input air flow in Nm3/h at standard conditions.

The operator shall determine Vprim by continuous flow measurement before the mixing with ammonia takes place. The operator shall determine Vsec by continuous flow measurement, including where the measurement is before the heat recovery unit. For Vseal the operator shall consider the purged airflow within the nitric acid production process.

For input air streams accounting for cumulatively less than 2,5 % of the total air flow, the competent authority may accept estimation methods for the determination of that air flow rate proposed by the operator based on industry best practices.

The operator shall provide evidence through measurements under normal operating conditions that the flue gas flow measured is sufficiently homogeneous to allow for the proposed measurement method. Where non-homogeneous flow is confirmed through these measurements, the operator shall take that into account when determining appropriate monitoring methods and when calculating the uncertainty in the N2O emissions.

The operator shall adjust all measurements to a dry gas basis and report them consistently.

B.4.   Oxygen (O2) concentrations

The operator shall measure the oxygen concentrations in the flue gas where necessary for calculating the flue gas flow in accordance with subsection B.3 of this section of Annex IV. In doing so, the operator shall comply with the requirements for concentration measurements within Article 41(1) and (2). In determining the uncertainty of N2O emissions, the operator shall take the uncertainty of O2 concentration measurements into account.

The operator shall adjust all measurements to a dry gas basis where required and report them consistently.

B.5.   Calculation of N2O emissions

For specific periods of unabated emissions of N2O from adipic acid, caprolactam, glyoxal and glyoxylic acid production, including unabated emissions from venting for safety reasons and when abatement plant fails, and where continuous emissions monitoring of N2O is technically not feasible, the operator shall subject to the approval of the specific methodology by the competent authority calculate N2O emissions using a mass balance methodology. For this purpose the overall uncertainty shall be similar to the result of applying the tier requirements of Article 41(1) and (2). The operator shall base the calculation method on the maximum potential emission rate of N2O from the chemical reaction taking place at the time and the period of the emission.

The operator shall take the uncertainty in any calculated emissions for a specific emission source into account in determining the annual average hourly uncertainty for the emission source.

B.6.   Determination of activity production rates

Production rates shall be calculated using daily production reports and hours of operation.

B.7.   Sampling rates

Valid hourly averages or averages for shorter reference periods shall be calculated in accordance with Article 44 for:

(a)	concentration of N2O in the flue gas;

(b)	total flue gas flow where this is measured directly and where required;

(c)	all gas flows and oxygen concentrations necessary to determine the total flue gas flow indirectly.

C.   Determination of annual CO2 equivalent – CO2(e)

The operator shall convert the total annual N2O emissions from all emissions sources, measured in tonnes to three decimal places, to annual CO2(e) in rounded tonnes, using the following formula and the GWP values in Annex VI section 3:

CO2(e) [t] = N2Oannual[t] × GWPN2O

Where:

N2Oannual = total annual N2O emissions, calculated according to equation 1 given in section 3 of Annex VIII.

The total annual CO2(e) generated by all emission sources and any direct CO2 emissions from other emission sources included under the greenhouse gas permit shall be added to the total annual CO2 emissions generated by the installation and shall be used for reporting and surrendering allowances.

Total annual emissions of N2O shall be reported in tonnes to three decimal places and as CO2(e) in rounded tonnes.

17.   PRODUCTION OF AMMONIA AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential emission sources for CO2 emissions: combustion of fuels supplying the heat for reforming or partial oxidation, fuels used as process input in the ammonia production process (reforming or partial oxidation), fuels used for other combustion processes including for the purpose of producing hot water or steam.

B.   Specific monitoring rules

For monitoring of emissions from combustion processes and from fuels used as process inputs, the standard methodology in accordance with Article 24 and section 1 of this Annex shall be applied.

Where CO2 from ammonia production is used as feedstock for the production of urea or other chemicals, or transferred out of the installation for any use not covered by Article 49(1), the related amount of CO2 shall be considered as emitted by the installation producing the CO2.

18.   PRODUCTION OF BULK ORGANIC CHEMICALS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall take into account at least the following sources of CO2 emissions: cracking (catalytic and non-catalytic), reforming, partial or full oxidation, similar processes which lead to CO2 emissions from carbon contained in hydrocarbon based feedstock, combustion of waste gases and flaring, and the burning of fuel in other combustion processes.

B.   Specific monitoring rules

Where the production of bulk organic chemicals is technically integrated in a mineral oil refinery, the operator of that installation shall apply the relevant provisions of section 2 of this Annex.

Notwithstanding the first subparagraph, the operator shall monitor emissions from combustion processes where the fuels used do not take part in or stem from chemical reactions for the production of bulk organic chemicals using the standard methodology in accordance with Article 24 and section 1 of this Annex. In all other cases, the operator may choose to monitor the emissions from bulk organic chemicals production by mass balance methodology in accordance with Article 25 or the standard methodology in accordance with Article 24. Where using the standard methodology, the operator shall provide evidence to the competent authority that the chosen methodology covers all relevant emissions that would also be covered by a mass-balance methodology.

For the determination of the carbon content under Tier 1, the reference emission factors as listed in Table 5 in Annex VI shall be applied. For substances not listed in Table 5 of Annex VI or other provisions of this Regulation, the operator shall calculate the carbon content from the stoichiometric carbon content in the pure substance and the concentration of the substance in the input or output stream.

19.   PRODUCTION OF HYDROGEN AND SYNTHESIS GAS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The operator shall include at least the following potential emission sources for CO2 emissions: fuels used in the hydrogen or synthesis gas production process (reforming or partial oxidation), and fuels used for other combustion processes including for the purpose of producing hot water or steam. Synthesis gas produced shall be considered as source stream under the mass balance methodology.

B.   Specific monitoring rules

For monitoring of emissions from combustion processes and from fuels used as process inputs in hydrogen production, the standard methodology in accordance with Article 24 and section 1 of this Annex shall be used.

For the monitoring of emissions from the production of synthesis gas, a mass balance in accordance with Article 25 shall be used. For emissions from separate combustion processes, the operator may choose to include them in the mass balance or to use the standard methodology in accordance with Article 24 at least for a part of the source streams, avoiding any gaps or double counting of emissions.

Where hydrogen and synthesis gas are produced at the same installation, the operator shall calculate CO2 emissions using either separate methodologies for hydrogen and for synthesis gas as outlined in the first two paragraphs of this subsection, or using one common mass balance.

20.   PRODUCTION OF SODA ASH AND SODIUM BICARBONATE AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC

A.   Scope

The emission sources and source streams for CO2 emissions from installations for the production of soda ash and sodium bicarbonate shall include:

(a)	fuels used for combustion processes, including fuels used for the purpose of producing hot water or steam;

(b)	raw materials, including vent gas from calcination of limestone, to the extent it is not used for carbonation;

(c)	waste gases from washing or filtration steps after carbonation, to the extent it is not used for carbonation.

B.   Specific monitoring rules

For the monitoring of emissions from the production of soda ash and sodium bicarbonate, the operator shall use a mass balance in accordance with Article 25. For emissions from combustion processes, the operator may choose to include them in the mass balance or to use the standard methodology in accordance with Article 24 at least for a part of the source streams, avoiding any gaps or double counting of emissions.

Where CO2 from the production of soda ash is used for the production of sodium bicarbonate, the amount of CO2 used for producing sodium bicarbonate from soda ash shall be considered as emitted by the installation producing the CO2.

21.   DETERMINATION OF GREENHOUSE GAS EMISSIONS FROM CO2 CAPTURE ACTIVITIES FOR THE PURPOSES OF TRANSPORT AND GEOLOGICAL STORAGE IN A STORAGE SITE PERMITTED UNDER DIRECTIVE 2009/31/EC

A.   Scope

CO2 capture shall be performed either by a dedicated installation receiving CO2 by transfer from one or more other installations, or by the same installation carrying out the activities producing the captured CO2 under the same greenhouse gas emissions permit. All parts of the installation related to CO2 capture, intermediate storage, transfer to a CO2 transport network or to a site for geological storage of CO2 greenhouse gas emissions shall be included in the greenhouse gas emissions permit and accounted for in the associated monitoring plan. In the case of the installation carrying out other activities covered by Directive 2003/87/EC, the emissions of those activities shall be monitored in accordance with the other relevant sections of this Annex.

The operator of a CO2 capture activity shall at least include the following potential sources of CO2 emission:

(a)	CO2 transferred to the capture installation;

(b)	combustion and other associated activities at the installation that are related to the capture activity, including fuel and input material use.

B.   Quantification of transferred and emitted CO2 amounts

B.1.   Installation level quantification

Each operator shall calculate the emissions by taking into account the potential CO2 emissions from all emission relevant processes at the installation, as well as the amount of CO2 captured and transferred to the transport network, using the following formula:

Ecapture installation = Tinput + Ewithout capture – Tfor storage

Where:

Ecapture installation = Total greenhouse gas emissions of the capture installation;

Tinput = Amount of CO2 transferred to the capture installation, determined in accordance with Article 40 to 46 and Article 49.

Ewithout capture = Emissions of the installation assuming the CO2 were not captured, meaning the sum of the emissions from all other activities at the installation, monitored in accordance with relevant sections of Annex IV;

Tfor storage = Amount of CO2 transferred to a transport network or a storage site, determined in accordance with Article 40 to 46 and Article 49.

In cases where CO2 capture is carried out by the same installation as the one from which the captured CO2 originates, the operator shall use zero for Tinput.

In cases of stand-alone capture installations, the operator shall consider Ewithout capture to represent the amount of emissions that occur from other sources than the CO2 transferred to the installation for capture. The operator shall determine those emissions in accordance with this Regulation.

In the case of stand-alone capture installations, the operator of the installation transferring CO2 to the capture installation shall deduct the amount Tinput from the emissions of its installation in accordance with Article 49.

B.2.   Determination of transferred CO2

Each operator shall determine the amount of CO2 transferred from and to the capture installation in accordance with Article 49 by means of measurement methodologies carried out in accordance with Articles 40 to 46.

Only where the operator of the installation transferring CO2 to the capture installation demonstrates to the satisfaction of the competent authority that CO2 transferred to the capture installation is transferred in total and to at least equivalent accuracy, may the competent authority allow that operator to use a calculation-based methodology in accordance with Article 24 or 25 to determine the amount Tinput instead of a measurement-based methodology in accordance with Article 40 to 46 and Article 49.

22.   DETERMINATION OF GREENHOUSE GAS EMISSIONS FROM THE TRANSPORT OF CO2 BY PIPELINES FOR GEOLOGICAL STORAGE IN A STORAGE SITE PERMITTED UNDER DIRECTIVE 2009/31/EC

A.   Scope

The boundaries for monitoring and reporting emissions from CO2 transport by pipeline shall be laid down in the transport network's greenhouse gas emissions permit, including all ancillary plant functionally connected to the transport network, including booster stations and heaters. Each transport network shall have a minimum of one start point and one end point, each connected to other installations carrying out one or more of the activities: capture, transport or geological storage of CO2. Start and end points may include bifurcations of the transport network and cross national borders. Start and end points as well as the installations they are connecting to, shall be laid down in the greenhouse gas emissions permit.

Each operator shall consider at least the following potential emission sources for CO2 emissions: combustion and other processes at installations functionally connected to the transport network including booster stations; fugitive emissions from the transport network; vented emissions from the transport network; and emissions from leakage incidents in the transport network.

B.   Quantification Methodologies for CO2

The operator of transport networks shall determine emissions using one of the following methods:

(a)	Method A (overall mass balance of all input and output streams) set out in subsection B.1;

(b)	Method B (monitoring of emission sources individually) set out in subsection B.2.

In choosing either Method A or Method B, each operator shall demonstrate to the competent authority that the chosen methodology will lead to more reliable results with lower uncertainty of the overall emissions, using best available technology and knowledge at the time of the application for the greenhouse gas emissions permit and approval of the monitoring plan, without incurring unreasonable costs. Where Method B is chosen each operator shall demonstrate to the satisfaction of the competent authority that the overall uncertainty for the annual level of greenhouse gas emissions for the operator's transport network does not exceed 7,5 %.

The operator of a transport network using Method B shall not add CO2 received from another installation permitted in accordance with Directive 2003/87/EC to its calculated level of emissions, and shall not subtract from its calculated level of emissions any CO2 transferred to another installation permitted in accordance with Directive 2003/87/EC.

Each operator of a transport network shall use Method A for the validation of the results of Method B at least once annually. For that validation, the operator may use lower tiers for the application of Method A.

B.1.   Method A

Each operator shall determine emissions in accordance with the following formula:

Where:

Emissions= Total CO2 emissions of the transport network [t CO2];

Eown activity = Emissions from the transport network's own activity, meaning not emissions stemming from the CO2 transported, but including emissions from fuel used in booster stations, monitored in accordance with the relevant sections of Annex IV;

TIN,i = Amount of CO2 transferred to the transport network at entry point i, determined in accordance with Articles 40 to 46 and Article 49.

TOUT,i = Amount of CO2 transferred out of the transport network at exit point i, determined in accordance with Articles 40 to 46 and Article 49.

B.2.   Method B

Each operator shall determine emissions considering all processes relevant to emissions at the installation as well as the amount of CO2 captured and transferred to the transport facility using the following formula:

Emissions [t CO2]= CO2 fugitive + CO2 vented + CO2 leakage events + CO2 installations

Where:

Emissions= Total CO2 emissions of the transport network [t CO2];

CO2 fugitive = Amount of fugitive emissions [t CO2] from CO2 transported in the transport network, including from seals, valves, intermediate compressor stations and intermediate storage facilities;

CO2 vented = Amount of vented emissions [t CO2] from CO2 transported in the transport network;

CO2 leakage events = Amount of CO2 [t CO2] transported in the transport network, which is emitted as the result of the failure of one or more components of the transport network;

CO2 installations = Amount of CO2 [t CO2] being emitted from combustion or other processes functionally connected to the pipeline transport in the transport network, monitored in accordance with the relevant sections of Annex IV.

B.2.1.   Fugitive emissions from the transport network

The operator shall consider fugitive emissions from any of the following types of equipment:

(a)

seals;

(b)	measurement devices;

(c)

valves;

(d)	intermediate compressor stations;

(e)	intermediate storage facilities.

The operator shall determine average emission factors EF (expressed in g CO2/unit time) per piece of equipment per occurrence where fugitive emissions can be anticipated at the beginning of operation, and by the end of the first reporting year in which the transport network is in operation at the latest. The operator shall review those factors at least every 5 years in the light of the best available techniques and knowledge.

The operator shall calculate fugitive emissions by multiplying the number of pieces of equipment in each category by the emission factor and adding up the results for the single categories as shown in the following equation:

The number of occurrences (Noccurr ) shall be the number of pieces of the given equipment per category, multiplied by the number of time units per year.

B.2.2.   Emissions from leakage events

The operator of a transport network shall provide evidence of the network integrity by using representative (spatial and time-related) temperature and pressure data. Where the data indicates that a leakage has occurred, the operator shall calculate the amount of CO2 leaked with a suitable methodology documented in the monitoring plan, based on industry best practice guidelines, including by use of the differences in temperature and pressure data compared to integrity related average pressure and temperature values.

B.2.3.   Vented emissions

Each operator shall provide in the monitoring plan an analysis regarding potential situations of venting emissions, including for maintenance or emergency reasons, and provide a suitable documented methodology for calculating the amount of CO2 vented, based on industry best practice guidelines.

23.   GEOLOGICAL STORAGE OF CO2 IN A STORAGE SITE PERMITTED UNDER DIRECTIVE 2009/31/EC

A.   Scope

The competent authority shall base the boundaries for monitoring and reporting of emissions from geological storage of CO2 on the delimitation of the storage site and storage complex as specified in the permit pursuant to Directive 2009/31/EC. Where leakages from the storage complex are identified and lead to emissions or release of CO2 into the water column, the operator shall immediately carry out all of the following:

(a)	notify the competent authority;

(b)	include the leakage as an emission source for the respective installation;

(c)	monitor and report the emissions.

Only when corrective measures in accordance with Article 16 of Directive 2009/31/EC have been taken and emissions or release into the water column from that leakage can no longer be detected shall the operator delete the respective leakage as emission source from the monitoring plan and no longer monitor and report those emissions.

Each operator of a geological storage activity shall consider at least the following potential emission sources for CO2 overall: fuel use by associated booster stations and other combustion activities including on-site power plants; venting from injection or enhanced hydrocarbon recovery operations; fugitive emissions from injection; breakthrough CO2 from enhanced hydrocarbon recovery operations; and leakages.

B.   Quantification of CO2 emissions

The operator of the geological storage activity shall not add CO2 received from another installation to its calculated level of emissions, and shall not subtract from its calculated level of emissions any CO2 which is geologically stored in the storage site or which is transferred to another installation.

B.1.   Vented and fugitive emissions from injection

The operator shall determine emissions from venting and fugitive emissions as follows:

CO2 emitted [t CO2 ] = V CO2 [t CO2] + F CO2 [t CO2]

Where:

V CO2 = amount of CO2 vented;

F CO2 = amount of CO2 from fugitive emissions.

Each operator shall determine V CO2 using measurement-based methodologies in accordance with Articles 41 to 46 of this Regulation. By way of derogation from the first sentence and upon approval by the competent authority, the operator may include in the monitoring plan an appropriate methodology for determining V CO2 based on industry best practice, where the application of measurement-based methodologies would incur unreasonable costs.

The operator shall consider F CO2 as one source, meaning that the uncertainty requirements associated with the tiers in accordance with section 1 of Annex VIII are applied to the total value instead of the individual emission points. Each operator shall provide in the monitoring plan an analysis regarding potential sources of fugitive emissions, and provide a suitable documented methodology to calculate or measure the amount of F CO2, based on industry best practice guidelines. For the determination of F CO2 the operator may use data collected in accordance with Article 32 to 35 and Annex II(1.1)(e) to (h) of Directive 2009/31/EC for the injection facility, where they comply with the requirements of this Regulation.

B.2.   Vented and fugitive emissions from enhanced hydrocarbon recovery operations

Each operator shall consider the following potential additional emission sources from enhanced hydrocarbon recovery (EHR):

(a)	the oil-gas separation units and gas recycling plant, where fugitive emissions of CO2 could occur;

(b)	the flare stack, where emissions might occur due to the application of continuous positive purge systems and during depressurisation of the hydrocarbon production installation;

(c)	the CO2 purge system, to avoid high concentrations of CO2 extinguishing the flare.

Each operator shall determine fugitive emissions or vented CO2 in accordance with subsection B.1 of this section of Annex IV.

Each operator shall determine emissions from the flare stack in accordance with subsection D of section 1 of this Annex, taking into account potential inherent CO2 in the flare gas in accordance with Article 48.

B.3.   Leakage from the storage complex

Emissions and release to the water column shall be quantified as follows:

Where:

L CO2 = the mass of CO2 emitted or released per calendar day due to the leakage in accordance with all of the following:

(a)	for each calendar day for which leakage is monitored, each operator shall calculate L CO2 as the average of the mass leaked per hour [t CO2/h] multiplied by 24;

(b)	each operator shall determine the mass leaked per hour in accordance with the provisions in the approved monitoring plan for the storage site and the leakage;

(c)	for each calendar day prior to commencement of monitoring, the operator shall take the mass leaked per day to equal the mass leaked per day for the first day of monitoring ensuring no under-estimation occurs;

Tstart = the latest of:

(a)	the last date when no emissions or release of CO2 into the water column from the source under consideration were reported;

(b)	the date the CO2 injection started;

(c)	another date such that there is evidence demonstrating to the satisfaction of the competent authority that the emission or release into the water column cannot have started before that date.

Tend = the date by which corrective measures in accordance with Article 16 of Directive 2009/31/EC have been taken and emissions or release of CO2 into the water column can no longer be detected.

The competent authority shall approve and allow the use of other methods for the quantification of emissions or release of CO2 into the water column from leakages where the operator can show to the satisfaction of the competent authority that such methods lead to a higher accuracy than the methodology set out in this subsection.

The operator shall quantify the amount of emissions leaked from the storage complex for each of the leakage events with a maximum overall uncertainty over the reporting period of 7,5 %. Where the overall uncertainty of the applied quantification methodology exceeds 7,5 %, each operator shall apply an adjustment, as follows:

CO2,Reported [t CO2] = CO2,Quantified [t CO2] × (1 + (UncertaintySystem [%]/100) – 0,075)

Where:

CO2,Reported = the amount of CO2 to be included in the annual emission report with regards to the leakage event in question;

CO2,Quantified = the amount of CO2 determined through the used quantification methodology for the leakage event in question;

UncertaintySystem = the level of uncertainty associated with the quantification methodology used for the leakage event in question.

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(1)  International Aluminium Institute; The Aluminium Sector Greenhouse Gas Protocol; October 2006;US Environmental Protection Agency and International Aluminium Institute; Protocol for Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) Emissions from Primary Aluminum Production; April 2008.