TABLE OF ANNEXES

ANNEX I

GENERAL GUIDELINES

CONTENTS

1. Introduction

2. Definitions

3. Monitoring and reporting principles

4. Monitoring of greenhouse gas emissions

4.1. Boundaries

4.2. Calculation and measurement based methodologies

4.3. The monitoring plan

5. Calculation-based methodologies for CO 2 emissions

5.1. Calculation formulae

5.2. Tiers of approaches

5.3. Fall-back approaches

5.4. Activity data

5.5. Emission factors

5.6. Oxidation and conversion factors

5.7. Transferred CO 2

6. Measurement-based methodologies

6.1. General

6.2. Tiers for measurement-based methodologies

6.3. Further procedures and requirements

7. Uncertainty assessment

7.1. Calculation

7.2. Measurement

8. Reporting

9. Retention of information

10. Control and verification

10.1. Data acquisition and handling

10.2. Control system

10.3. Control activities

10.3.1. Procedures and responsibilities

10.3.2. Quality assurance

10.3.3. Reviews and validation of data

10.3.4. Outsourced processes

10.3.5. Corrections and corrective action

10.3.6. Records and documentation

10.4. Verification

10.4.1. General principles

10.4.2. Verification methodology

11. Emission factors

12. List of CO 2 -neutral biomass

13. Determination of activity-specific data and factors

13.1. Determination of net calorific values and emission factors for fuels

13.2. Determination of activity specific oxidation factors

13.3. Determination of process emission factors, conversion factors and composition data

13.4. Determination of a biomass fraction

13.5. Requirements for determination of fuel and material properties

13.5.1. Use of accredited laboratories

13.5.2. Use of non-accredited laboratories

13.5.3. Online gas analyser and gas chromatographs

13.6. Sampling methods and frequency of analyses

14. Reporting format

14.1. Identification of installation

14.2. Overview activities and emissions within an installation

14.3. Combustion emissions (calculation)

14.4. Process emissions (calculation)

14.5. Mass-balance approach

14.6. Measurement approach

15. Reporting categories

15.1. IPCC reporting format

15.2. IPPC source category code of EPRTR Regulation

16. Requirements for installations with low emissions

1. INTRODUCTION

This Annex contains the general guidelines for the monitoring and reporting of emissions from the activities listed in Annex I to Directive 2003/87/ECof greenhouse gases specified in relation to those activities. Additional guidelines on activity-specific emissions are set out in Annexes II-XI.

2. DEFINITIONS

For the purposes of this Annex and Annexes II to XII the definitions of Directive 2003/87/EC shall apply.

1. In addition the following basic definitions shall apply: (a) ‘activities’ means the activities listed in Annex I to Directive 2003/87/EC; (b) ‘competent authority’ means the competent authority or authorities designated in accordance with Article 18 of the Directive 2003/87/EC; (c) ‘emission source’ means a separately identifiable part (point or process) of an installation from which relevant greenhouse gases are emitted; (d) ‘source stream’ means a specific fuel type, raw material or product giving rise to emissions of relevant greenhouse gases at one or more emission sources as a result of its consumption or production; (e) ‘monitoring methodology’ means the sum of approaches used by an operator to determine the emissions of a given installation; (f) ‘monitoring plan’ means a detailed, complete and transparent documentation of the monitoring methodology of a specific installation, including documentation of the data acquisition and data handling activities, and the system to control the trueness thereof; (g) ‘tier’ means a specific element of a methodology for determining activity data, emission factors and oxidation or conversion factors; (h) ‘annual’ means a period of time covering a calendar year from 1 January to 31 December; (i) ‘reporting period’ means one calendar year during which emissions have to be monitored and reported; (j) ‘trading period’ means a multiple year phase of the emission trading scheme (e.g. 2005-2007 or 2008-2012) for which a national allocation plan is issued by the Member State in accordance with Article 11(1) and (2) of the Directive 2003/87/EC.

2. The following definitions shall apply in relation to emissions, fuels and materials: (a) ‘combustion emissions’ means greenhouse gas emissions occurring during the exothermic reaction of a fuel with oxygen; (b) ‘process emissions’ means greenhouse gas emissions other than combustion emissions occurring as a result of intentional and unintentional reactions between substances or their transformation, including the chemical or electrolytic reduction of metal ores, the thermal decomposition of substances, and the formation of substances for use as product or feedstock; (c) ‘inherent CO2’ means CO2 which is part of a fuel; (d) ‘conservative’ means that a set of assumptions is defined in order to ensure that no under-estimation of annual emissions occurs; (e) ‘batch’ means an amount of fuel or material representatively sampled and characterised and transferred as one shipment or continuously over a specific period of time; (f) ‘commercially traded fuels’ means fuels of specified composition which are frequently and freely traded, if the specific batch has been traded between economically-independent parties, including all commercial standard fuels, natural gas, light and heavy fuel oil, coal, petroleum coke; (g) ‘commercially traded materials’ means materials of specified composition which are frequently and freely traded, if the specific batch has been traded between economically independent parties; (h) ‘commercial standard fuel’ means the internationally standardised commercial fuels which exhibit a 95 % confidence interval of not more than ± 1 % for their specified calorific value, including gas oil, light fuel oil, gasoline, lamp oil, kerosene, ethane, propane and butane.

3. The following definitions shall apply in relation to measurement: (a) ‘accuracy’ means the closeness of the agreement between the result of a measurement and the true value of the particular quantity (or a reference value determined empirically using internationally accepted and traceable calibration materials and standard methods), taking into account both, random and systematic factors; (b) ‘uncertainty’ means a parameter, associated with the result of the determination of a quantity, that characterises the dispersion of the values that could reasonably be attributed to the particular quantity, including the effects of systematic as well as of random factors and expressed in per cent and describes a confidence interval around the mean value comprising 95 % of inferred values taking into account any asymmetry of the distribution of values; (c) ‘arithmetic mean’ means the sum of all the members of a set of values divided by the number of items in the set; (d) ‘measurement’ means a set of operations having the object of determining the value of a quantity; (e) ‘measurement instrument’ means a device intended to be used to make measurements, alone or in conjunction with supplementary device(s); (f) ‘measurement system’ means a complete set of measurement instruments and other equipment, like sampling and data processing equipment, used for the determination of variables like the activity data, the carbon content, the calorific value or the emission factor of the CO2 emissions; (g) ‘calibration’ means the set of operations, which establish, under specified conditions, the relations between values indicated by a measuring instrument or measuring system, or values represented by a material measure or a reference material and the corresponding values of a quantity realised by a reference standard; (h) ‘continuous emission measurement’ means a set of operations having the objective of determining the value of a quantity by means of periodic (several per hour) measurements, applying either in-situ measurements in the stack or extractive procedures with a measurement instrument located close to the stack; it does not include measurement approaches based on the collection of individual samples from the stack; (i) ‘standard conditions’ means temperature of 273,15 K (i.e. 0 oC) and pressure conditions of 101 325 Pa defining normal cubic meters (Nm3).

4. The following definitions relating to calculation-based methodologies and measurement-based methodologies for CO2 emissions shall apply: (a) ‘unreasonable costs’ means costs of a measure disproportionate to its overall benefits as established by the competent authority. In respect to the choice of tier levels, the threshold may be defined as the value of the allowances corresponding to an improvement of the level of accuracy. For measures increasing the quality of reported emissions but without direct impact on accuracy, unreasonable cost may correspond to a fraction exceeding an indicative threshold of 1 % of the average value of the available emissions data reported for the previous trading period. For installations without this history, data from representative installations carrying out the same or comparable activities are used as reference and scaled according to their capacity. (b) ‘technically feasible’ means that technical resources capable of meeting the needs of a proposed system can be acquired by the operator in the required time; (c) ‘de minimis source streams’ means a group of minor source streams selected by the operator and jointly emitting 1 kilotonnes of fossil CO2 or less per year, or that contribute less than 2 % (up to a total maximum contribution of 20 kilotonnes of fossil CO2 per year) of total annual emissions of fossil CO2 of that installation before subtraction of transferred CO2, whichever is the highest in terms of absolute emissions; (d) ‘major source streams’ means a group of source streams which do not belong to the group of ‘minor source streams’; (e) ‘minor source streams’ means those source streams selected by the operator to jointly emit 5 kilotonnes of fossil CO2 or less per year or to contribute less than 10 % (up to a total maximum contribution of 100 kilotonnes of fossil CO2 per year), to the total annual emissions of fossil CO2 of an installation before subtraction of transferred CO2, whichever is the highest in terms of absolute emissions. (f) ‘biomass’ means non-fossilised and biodegradable organic material originating from plants, animals and micro-organisms, including products, by-products, residues and waste from agriculture, forestry and related industries as well as the non-fossilised and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilised and biodegradable organic material; (g) ‘pure’ relating to a substance means that a material or fuel consists of at least 97 % (related to mass) of the specified substance or element — corresponding to the commercial classification of ‘purum’. For biomass this relates to the fraction of biomass carbon in the total amount of carbon in the fuel or material; (h) ‘energy-balance method’ means a method to estimate the amount of energy used as fuel in a boiler, calculated as sum of utilisable heat and all relevant losses of energy by radiation, transmission and via the flue gas.

5. the following definitions relating to control and verification shall apply: (a) ‘control risks’ means the susceptibility of a parameter in the Annual Emissions Report to material misstatements that will not be prevented or detected and corrected on a timely basis by the control system; (b) ‘detection risk’ means the risk that the verifier will not detect a material misstatement or a material non-conformity; (c) ‘inherent risk’ means the susceptibility of a parameter in the annual emissions report to material misstatements, assuming that there were no related control activities; (d) ‘verification risk’ means the risk that the verifier expresses an inappropriate verification opinion. Verification risk is a function of inherent risks, control risks, and the detection risk; (e) ‘reasonable assurance’ means a high but not absolute level of assurance, expressed positively in the verification opinion, whether the emissions report subject to verification is free from material misstatement and whether the installation does not have material non-conformities; (f) ‘materiality level’ means the quantitative threshold or cut-off point to be used to determine the appropriate verification opinion on the emission data reported in the annual emissions report; (g) ‘level of assurance’ means the degree to which the verifier is confident in the verification conclusions that it has been proved whether or not the information reported in the annual emission report for an installation is free from material misstatement; (h) ‘non-conformity’ means any act or omission of an act by the installation being under verification, either intentional or unintentional, that is contrary to the requirements in the monitoring plan approved by the competent authority under the installation's permit; (i) ‘material non-conformity’ means that a non-conformity to the requirements in the monitoring plan approved by the competent authority under the installation's permit, could lead to a different treatment of the installation by the competent authority; (j) ‘material misstatement’ means a misstatement (omissions, misrepresentations and errors, not considering the permissible uncertainty) in the annual emissions report that, to the professional judgment of the verifier, could affect the treatment of the annual emissions report by the competent authority, e.g. when the misstatement exceeds the materiality level; (k) ‘accreditation’ in the context of verification means the issuing of a statement by an accreditation body based on its decision following a detailed assessment related to a verifier conveying formal demonstration of its competence and independence to carry out verification in accordance with specified requirements; (l) ‘verification’ means the activities carried out by a verifier to be able to provide a verification opinion as described in Article 15 and Annex V of the Directive 2003/87/EC; (m) ‘verifier’ means a competent, independent, accredited verification body or person with responsibility for performing and reporting on the verification process, in accordance with the detailed requirements established by the Member State pursuant to Annex V of the Directive 2003/87/EC.

3. MONITORING AND REPORTING PRINCIPLES

To ensure the accurate and verifiable monitoring and reporting of greenhouse gas emissions under Directive 2003/87/EC, monitoring and reporting shall be based on the following principles:

Completeness. Monitoring and reporting for an installation shall cover all process and combustion emissions from all emission sources and source streams belonging to activities listed in Annex I to Directive 2003/87/EC and of all greenhouse gases specified in relation to those activities while avoiding double-counting.

Consistency. Monitored and reported emissions shall be comparable over time, using the same monitoring methodologies and data sets. Monitoring methodologies can be changed in accordance with the provisions of these Guidelines if the accuracy of the reported data is improved. Changes in monitoring methodologies shall be subject to approval from the competent authority and shall be fully documented in accordance with these guidelines.

Transparency. Monitoring data, including assumptions, references, activity data, emission factors, oxidation factors and conversion factors shall be obtained, recorded, compiled, analysed and documented in a manner that enables the reproduction of the determination of emissions by the verifier and the competent authority.

Trueness. It shall be ensured that the emission determination is systematically neither over nor under true emissions. Sources of uncertainties shall be identified and reduced as far as practicable. Due diligence shall be exercised to ensure that the calculation and measurement of emissions exhibit highest achievable accuracy. The operator shall enable reasonable assurance of the integrity of reported emissions to be determined. Emissions shall be determined using the appropriate monitoring methodologies set out in these Guidelines. All metering or other testing equipment used to report monitoring data shall be appropriately applied, maintained and calibrated, and checked. Spreadsheets and other tools used to store and manipulate monitoring data shall be free from error. Reported emissions and related disclosures shall be free from material misstatement, avoid bias in the selection and presentation of information, and provide a credible and balanced account of an installation's emissions.

Cost effectiveness. In selecting a monitoring methodology, the improvements from greater accuracy shall be balanced against the additional costs. Hence, monitoring and reporting of emissions shall aim for the highest achievable accuracy, unless this is technically not feasible or will lead to unreasonably high costs. The monitoring methodology itself shall describe the instructions to the operator in a logical and simple manner, avoiding duplication of effort and taking into account the existing systems in place at the installation.

Faithfulness. A verified emissions report shall be capable of being depended upon by users to represent faithfully that which it either purports to represent or could reasonably be expected to represent.

Improvement of performance in monitoring and reporting emissions. The process of verifying the emission reports shall be an effective and reliable tool in its support of quality assurance and quality control procedures, providing information upon which an operator can act to improve its performance in monitoring and reporting emissions.

4. MONITORING OF GREENHOUSE GAS EMISSIONS

4.1. BOUNDARIES

The monitoring and reporting process for an installation shall include all relevant greenhouse gas emissions from all emission sources and/or source streams belonging to activities carried out at the installation and listed in Annex I to Directive 2003/87/EC, as well as from activities and greenhouse gases included by a Member State pursuant Article 24 of Directive 2003/87/EC.

Article 6(2)(b) of Directive 2003/87/EC requires that greenhouse gas emissions permits shall contain a description of the activities and emissions from the installation. Therefore, all emission sources and source streams from activities listed in Annex I to Directive 2003/87/EC that are to be monitored and reported shall be listed in the permit. Article 6(2)(c) of Directive 2003/87/EC requires that greenhouse gas emissions permits shall contain monitoring requirements, specifying monitoring methodology and frequency.

Emissions from mobile internal combustion engines for transportation purposes shall be excluded from the emission estimates.

The monitoring of emissions shall include emissions from regular operations and abnormal events including start-up and shut-down, and emergency situations over the reporting period.

If the separate or combined production capacities, or outputs of one or several activities belonging to the same activity subheading in Annex I to Directive 2003/87/EC exceed the respective threshold defined in that Annex in one installation or on one site, all emissions from all emission sources and/or source streams of all activities listed in that Annex in the respective installation or site shall be monitored and reported.

Whether an additional combustion installation, such as a combined heat and power installation, is regarded as part of an installation carrying out another Annex I activity or as a separate installation depends on local circumstances and shall be established in the installation's greenhouse gas emission permit.

All emissions from an installation shall be assigned to that installation, regardless of exports of heat or electricity to other installations. Emissions associated with the production of heat or electricity imported from other installations shall not be assigned to the importing installation.

4.2. CALCULATION AND MEASUREMENT-BASED METHODOLOGIES

Annex IV to Directive 2003/87/EC permits a determination of emissions using either:

— a calculation-based methodology, determining emissions from source streams based on activity data obtained by means of measurement systems and additional parameters from laboratory analyses or standard factors;

— a measurement-based methodology, determining emissions from an emission source by means of continuous measurement of the concentration of the relevant greenhouse gas in the flue gas and of the flue gas flow.

The operator may propose to use a measurement based methodology if he can demonstrate that:

— it reliably results in a more accurate value of annual emissions of the installation than an alternative calculation based methodology, while avoiding unreasonable costs; and

— the comparison between measurement and calculation-based methodology is based on an identical set of emission sources and source streams.

The use of a measurement-based methodology shall be subject to the approval of the competent authority. For each reporting period the operator shall corroborate the measured emissions by means of calculation-based methodology in accordance with the provisions of Section 6.3(c).

The operator may, with the approval of the competent authority, combine measurement and calculation-based methodologies for different emission sources and source streams belonging to one installation. The operator shall ensure and demonstrate that neither gaps nor double counting concerning emissions occur.

4.3. THE MONITORING PLAN

Pursuant to Article 6(2)(c) of Directive 2003/87/EC greenhouse gas emissions permits shall contain monitoring requirements, specifying monitoring methodology and frequency.

The monitoring methodology is part of the monitoring plan which shall be approved by the competent authority in accordance with the criteria set out in this Section and its subsections. The Member State or its competent authorities shall ensure that the monitoring methodology to be applied by installations shall be specified either under the conditions of the permit or, where consistent with Directive 2003/87/EC, in general binding rules.

The competent authority shall check and approve the monitoring plan prepared by the operator before the start of the reporting period, and again after any substantial changes to the monitoring methodology are applied to an installation as listed three paragraphs below.

Subject to Section 16, the monitoring plan shall contain the following contents:

(a) the description of the installation and activities carried out by the installation to be monitored;

(b) information on responsibilities for monitoring and reporting within the installation;

(c) a list of emissions sources and source streams to be monitored for each activity carried out within the installation;

(d) a description of the calculation-based methodology or measurement-based methodology to be used;

(e) a list and description of the tiers for activity data, emission factors, oxidation and conversion factors for each of the source streams to be monitored;

(f) a description of the measurement systems, and the specification and exact location of the measurement instruments to be used for each of the source streams to be monitored;

(g) evidence demonstrating compliance with the uncertainty thresholds for activity data and other parameters (where applicable) for the applied tiers for each source stream;

(h) if applicable, a description of the approach to be used for the sampling of fuel and materials for the determination of net calorific value, carbon content, emission factors, oxidation and conversion factor and biomass content for each of the source streams;

(i) a description of the intended sources or analytical approaches for the determination of the net calorific values, carbon content, emission factor, oxidation factor, conversion factor or biomass fraction for each of the source streams;

(j) if applicable, a list and description of non-accredited laboratories and relevant analytical procedures including a list of all relevant quality assurance measures, e.g. inter-laboratory comparisons as described in Section 13.5.2;

(k) if applicable, a description of continuous emission measurement systems to be used for the monitoring of an emission source, i.e. the points of measurement, frequency of measurements, equipment used, calibration procedures, data collection and storage procedures and the approach for corroborating calculation and the reporting of activity data, emission factors and alike;

(l) if applicable, where the so-called ‘fall-back approach’ (Section 5.3) is applied: a comprehensive description of the approach and the uncertainty analysis, if not already covered by items (a) to (k) of this list;

(m) a description of the procedures for data acquisition, handling activities and control activities as well as a description of the activities (see Section 10.1-3);

(n) where applicable, information on relevant links with activities undertaken under the Community eco-management and audit scheme (EMAS) and other environmental management systems (e.g. ISO14001:2004), in particular on procedures and controls with relevance to greenhouse gas emissions monitoring and reporting.

The monitoring methodology shall be changed if this improves the accuracy of the reported data, unless this is technically not feasible or would lead to unreasonably high costs.

A substantial change to the monitoring methodology as part of the monitoring plan shall be subject to the approval of the competent authority if it concerns:

— a change of the categorisation of the installation as laid down in Table 1,

— a change between the calculation-based or the measurement-based methodology used to determine emissions,

— an increase of the uncertainty of the activity data or other parameters (where applicable) which implies a different tier level.

All other changes and proposed changes in monitoring methodology or the underlying data sets shall be notified to the competent authority without undue delay after the operator has become aware of it or could in all reasonableness have become aware of it, unless otherwise specified in the monitoring plan.

Changes to the monitoring plan shall be clearly stated, justified and fully documented in internal records of the operator.

A competent authority shall require the operator to change its monitoring plan if its monitoring plan is no longer in conformity with the rules laid down in these Guidelines.

To exchange information between the competent authorities and the Commission on monitoring, reporting and verification under these guidelines and its coherent application Member States shall facilitate an annual quality assurance and evaluation process of monitoring, reporting and verification initiated by the Commission pursuant to Article 21(3) of Directive 2003/87/EC.

5. CALCULATION-BASED METHODOLOGIES FOR CO2 EMISSIONS

5.1. CALCULATION FORMULAE

Calculation of CO2 emissions shall be based either on the following formula:

CO2 emissions = activity data * emission factor * oxidation factor

or on an alternative approach if defined in the activity-specific guidelines.

The expressions within this formula are specified for combustion emission and process emissions as follows:

Combustion emissions

Activity data shall be based on fuel consumption. The quantity of fuel used shall be expressed in terms of energy content as TJ, unless otherwise indicated in these guidelines. The emission factor shall be expressed as tCO2/TJ, unless otherwise indicated in these guidelines. When a fuel is consumed not all of the carbon in the fuel is oxidised to CO2. Incomplete oxidation occurs due to inefficiencies in the combustion process that leave some of the carbon unburned or partly oxidised as soot or ash. Un-oxidised or partially oxidized carbon is taken into account in the oxidation factor which shall be expressed as a fraction. The oxidation factor shall be expressed as a fraction of one. The resulting calculation formula is:

CO2 emissions = fuel flow [t or Nm3] * net calorific value [TJ/t or TJ/Nm3] * emission factor [tCO2/TJ] * oxidation factor

The calculation of combustion emissions is further specified in Annex II.

Process emissions

Activity data shall be based on material consumption, throughput or production output and expressed in t or Nm3. The emission factor shall be expressed in [tCO2/t or tCO2/Nm3]. Carbon contained in input materials, which is not converted to CO2 during the process, is taken into account in the conversion factor which shall be expressed as a fraction. In the event that a conversion factor is taken into account in the emission factor, a separate conversion factor shall not be applied. The quantity of input material used shall be expressed in terms of mass or volume [t or Nm3]. The resulting calculation formula is:

CO2 emissions = activity data [t or Nm3] * emission factor [tCO2/t or Nm3] * conversion factor

The calculation of process emissions is further specified in the activity-specific guidelines in the Annexes II-XI. Not all calculation methods in Annexes II-XI use a conversion factor.

5.2. TIERS OF APPROACHES

The activity-specific guidelines set out in Annexes II to XI contain specific methodologies for determining the following variables: activity data (consisting of the two variables fuel/material flow and net calorific value), emission factors, composition data, oxidation and conversion factors. These different approaches are referred to as tiers. The increasing numbering of tiers from one upwards reflects increasing levels of accuracy, with the highest numbered tier as the preferred tier.

The operator may apply different approved tier levels to the different variables fuel/material flow, net calorific value, emission factors, composition data, oxidation or conversion factors used within a single calculation. The choice of tiers shall be subject to approval by the competent authority (see Section 4.3).

Equivalent tiers are referred to with the same tier number and a specific alphabetic character (e.g. Tier 2a and 2b). For those activities where alternative calculation methods are provided within these guidelines (e.g. in Annex VII, ‘Method A — kiln input based’ and ‘Method B — clinker output based’) an operator may only change from one method to the other if he can demonstrate to the satisfaction of the competent authority that such change will lead to a more accurate monitoring and reporting of the emissions of the relevant activity.

The highest tier approach shall be used by all operators to determine all variables for all source streams for all category B or C installations. Only if it is shown to the satisfaction of the competent authority that the highest tier approach is technically not feasible or will lead to unreasonably high costs, may a next lower tier be used for that variable within a monitoring methodology. For installations with emissions of more than 500 kilotonnes of fossil CO2 annually (i.e. the ‘Category C installations’), the Member State shall notify to the Commission pursuant to Article 21 of Directive 2003/87/EC if the application of a combination of highest tier approaches for all major source streams does not take place.

Subject to Section 16 Member States shall ensure that operators apply for all major source streams, as a minimum the tiers as set out in Table 1 below, unless this is technically not feasible.

Both subject to approval by the competent authority, the operator may select as a minimum the Tier 1 level for the variables used to calculate emissions from minor source streams and apply approaches for monitoring and reporting using his own no-tier estimation method for de minimis source streams.

The operator shall without undue delay propose changes to the tiers applied when:

— accessible data has changed, allowing for higher accuracy in the determination of emissions,

— previously non-existent emission has started,

— the range of fuels or relevant raw materials has substantially changed,

— errors were detected in data resulting from the monitoring methodology,

— the competent authority has requested a change.

For biomass fuel and materials qualifying as pure, no-tier approaches may be applied for installations, or technically identifiable parts thereof, unless the respective value is to be used for the subtraction of biomass derived CO2 from emissions determined by means of continuous emission measurement. These no-tier approaches include the energy-balance method. Emissions of CO2 from fossil contaminants to fuels and materials qualifying as pure biomass shall be reported under the biomass source stream and may be estimated using no-tier approaches. Mixed fuels and materials containing biomass shall be characterised applying the provisions of Section 13.4 of this Annex, unless the source stream qualifies as de minimis.

If the highest tier methodology or the variable-specific agreed tier is temporarily not feasible for technical reasons an operator may apply the highest achievable tier until such time as the conditions for application of the former tier have been restored. The operator shall, without undue delay, provide proof of the necessity for a change of tiers to the competent authority and details of the interim monitoring methodology. The operator shall take all necessary action to allow the prompt restoration of the original tier for monitoring and reporting purposes.

Changes of tiers shall be fully documented. The treatment of minor data gaps which result from downtimes of measurement systems shall follow good professional practice ensuring a conservative estimation of emissions, considering the provisions of the Integrated Pollution Prevention and Control (IPPC) Reference Document on the General Principles of Monitoring of July 2003 (1). When tiers are changed within a reporting period the results for the affected activity shall be calculated and reported as separate sections of the annual report to the competent authority for the respective parts of the reporting period.

Table 1

Minimum requirements

(‘n.a.’ means ‘not applicable’)

Column A for ‘category A installations’ (means installations with average reported annual emissions over the previous trading period (or a conservative estimate or projection if reported emissions are not available or no longer applicable) equal to or less than 50 kilotonnes of fossil CO2 before subtraction of transferred CO2),

Column B for ‘category B installations’ (means installations with average reported annual emissions over the previous trading period (or a conservative estimate or projection if reported emissions are not available or no longer applicable) of greater 50 kilotonnes and equal to or less than 500 kilotonnes of fossil CO2 before subtraction of transferred CO2) and,

Column C for ‘category C installations’ (means installations with average reported annual emissions over the previous trading period (or a conservative estimate or projection if reported emissions are not available or no longer applicable) of greater than 500 kilotonnes of fossil CO2 before subtraction of transferred CO2).

Activity data Emission factor Composition data Oxidation factor Conversion factor Fuel flow Net calorific value Annex/Activity A B C A B C A B C A B C A B C A B C II: Combustion Commercial standard fuels 2 3 4 2a/2b 2a/2b 2a/2b 2a/2b 2a/2b 2a/2b n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. Other gaseous and liquid fuels 2 3 4 2a/2b 2a/2b 3 2a/2b 2a/2b 3 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. Solid fuels 1 2 3 2a/2b 3 3 2a/2b 3 3 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. Mass-balance approach for carbon black production and gas processing terminals 1 2 3 n.a. n.a. n.a. n.a. n.a. n.a. 1 2 2 n.a. n.a. n.a. n.a. n.a. n.a. Flares 1 2 3 n.a. n.a. n.a. 1 2a/b 3 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. Scrubbing Carbonate 1 1 1 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. Gypsum 1 1 1 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.





Activity data Emission factor Composition data Conversion factor Material flow Net calorific value A B C A B C A B C A B C A B C III: Refineries Catalytic cracker regeneration 1 1 1 n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. Hydrogen production 1 2 2 n.a. n.a. n.a. 1 2 2 n.a. n.a. n.a. n.a. n.a. n.a. IV: Coke ovens Mass balance 1 2 3 n.a. n.a. n.a. n.a. n.a. n.a. 2 3 3 n.a. n.a. n.a. Fuel as process input 1 2 3 2 2 3 2 3 3 n.a. n.a. n.a. n.a. n.a. n.a. V: Metal ore roasting and sintering Mass balance 1 2 3 n.a. n.a. n.a. n.a. n.a. n.a. 2 3 3 n.a. n.a. n.a. Carbonate Input 1 1 2 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. 1 1 1 VI: Iron and steel Mass balance 1 2 3 n.a. n.a. n.a. n.a. n.a. n.a. 2 3 3 n.a. n.a. n.a. Fuel as process input 1 2 3 2 2 3 2 3 3 n.a. n.a. n.a. n.a. n.a. n.a. VII: Cement Kiln input based 1 2 3 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. 1 1 2 Clinker output 1 1 2 n.a. n.a. n.a. 1 2 3 n.a. n.a. n.a. 1 1 2 CKD 1 1 2 n.a. n.a. n.a. 1 2 2 n.a. n.a. n.a. n.a. n.a. n.a. Non-carbonate carbon 1 1 2 n.a. n.a. n.a. 1 1 2 n.a. n.a. n.a. 1 1 2 VIII: Lime Carbonates 1 2 3 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. 1 1 2 Alkali earth oxide 1 1 2 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. 1 1 2 IX: Glass Carbonates 1 1 2 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. n.a. n.a. n.a. X: Ceramic Carbon inputs 1 1 2 n.a. n.a. n.a. 1 2 3 n.a. n.a. n.a. 1 1 2 Alkali oxide 1 1 2 n.a. n.a. n.a. 1 2 3 n.a. n.a. n.a. 1 1 2 Scrubbing 1 1 1 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. n.a. n.a. n.a. XI: Pulp and paper Standard method 1 1 1 n.a. n.a. n.a. 1 1 1 n.a. n.a. n.a. n.a. n.a. n.a.

5.3. FALL-BACK APPROACHES

In cases for which it is technically not feasible or would lead to unreasonable costs to apply at least Tier 1 requirements for all (except the de minimis) source streams, the operator shall apply a so-called ‘fall-back approach’. This exempts the operator from the application of Section 5.2 of this Annex and permits the design of a fully customized monitoring methodology. The operator shall demonstrate to the satisfaction of the competent authority that by applying this alternative monitoring methodology for the whole installation, the overall uncertainty thresholds given in Table 2 for the annual level of greenhouse gas emissions for the whole installation are met.

The uncertainty analysis shall quantify the uncertainties of all variables and parameters used for the calculation of the annual emission level taking into account the ISO — Guide to the Expression of Uncertainty in Measurement (1995) (2) and ISO 5168:2005. The analysis shall be carried out before approval of the monitoring plan by the competent authority on the basis of previous year data and shall be updated on an annual basis. This annual update shall be prepared together with the annual emissions report and be subject to verification.

Respective installations applying the fall-back approach are to be notified by Member States to the Commission pursuant to Article 21 of Directive 2003/87/EC. The operator shall determine and report in the annual emission report, data where available, or best estimates of activity data, net calorific values, emission factors, oxidation factors and other parameters — using laboratory analyses where appropriate. The respective approaches shall be laid down in the monitoring plan and be approved by the competent authority. Table 2 does not apply for installations determining their greenhouse gas emissions using continuous emission monitoring systems applying Annex XII.

Table 2

Fall-back overall uncertainty thresholds

Installation category Uncertainty threshold to be met for total annual emission value A ±7,5 % B ±5,0 % C ±2,5 %

5.4. ACTIVITY DATA

Activity data represents information on material flow, consumption of fuel, input material or production output expressed as energy [TJ] (in exceptional cases also as mass or volume [t or Nm3], see Section 5.5) in the case of fuels and mass or volume in the case of raw materials or products [t or Nm3].

The determination of activity data by the operator can be based on the invoiced amount of fuel or material determined in compliance with Annex I and the approved tiers of Annexes II to XI.

Where activity data for the calculation of emissions cannot be determined directly, the activity data shall be determined via an assessment of stock changes:

Material C = Material P + (Material S - Material E) - Material O

Where:

Material C : Material processed during the reporting period Material P : Material purchased during the reporting period Material S : Material stock at the beginning of the reporting period Material E : Material stock at the end of the reporting period Material O : Material used for other purposes (transportation or re-sold)

In cases in which it is technically not feasible or would lead to unreasonably high costs to determine ‘Material S’ and ‘Material E’ by direct measurement, the operator may estimate these two quantities based on

— data from previous years and correlation with output for the reporting period, or

— documented methods and respective data in audited financial statements for the reporting period.

In cases in which a determination of annual activity data for precisely a whole calendar year is technically not feasible or would lead to unreasonable costs, the operator may choose the next appropriate working day to separate a reporting year from the following one. The deviations which could apply to one or several source streams, shall be clearly recorded, form the basis of a value representative for the calendar year and be considered consistently for the subsequent year.

5.5. EMISSION FACTORS

Emission factors are based on the carbon content of fuels or input materials and expressed as tCO2/TJ (combustion emissions), or tCO2/t or tCO2/Nm3 (process emissions).

In order to achieve highest transparency and widest possible consistency with national greenhouse gas inventories, the use of emission factors for a fuel expressed as tCO2/t rather than tCO2/TJ for combustion emissions is restricted to cases where unreasonable costs would otherwise be incurred by the operator.

For the conversion of carbon into the respective value for CO2 the factor (3) of 3,664 [tCO2/t C] shall be used.

Emission factors and provisions for the development of activity-specific emission factors are set out below in Section 11 and 13 of this Annex.

Biomass is considered as CO2 neutral. An emission factor of 0 [tCO2/TJ or t or Nm3] shall be applied to biomass. An exemplary list of different types of materials accepted as biomass is given in Section 12 of this Annex.

For fuels or materials containing both fossil and biomass carbon, a weighted emission factor shall be applied, based on the proportion of the fossil carbon in the fuel's overall carbon content. This calculation shall be transparent and documented in accordance with the rules and procedures of Section 13 of this Annex.

Inherent CO2 which is transferred into an installation under the EU-ETS as part of a fuel (e.g. blast furnace gas, coke oven gas or natural gas) shall be included in the emission factor for that fuel.

Subject to approval by the competent authority, inherent CO2 originating from a source stream but subsequently being transferred out of an installation as part of a fuel may be deducted from the emissions of that installation — independently of whether it is supplied to another EU-ETS installation or not. In any case, it shall be reported as a memo item. Installations concerned are to be notified by Member States to the Commission under the obligations of Article 21 of Directive 2003/87/EC.

5.6. OXIDATION AND CONVERSION FACTORS

An oxidation factor for combustion emissions or a conversion factor for process emissions shall be used to reflect the proportion of carbon which is not oxidised or converted in the process. For oxidation factors the requirement to apply the highest tier is waived. If different fuels are used within an installation and activity specific oxidation factors are calculated, subject to approval by the competent authority, the operator may determine one aggregate oxidation factor for the activity and apply it to all fuels, or unless biomass is used, attribute incomplete oxidation to one major fuel stream and use a value of 1 for the others.

5.7. TRANSFERRED CO2

Subject to approval by the competent authority, the operator may subtract from the calculated level of emissions of the installation any CO2 which is not emitted from the installation but transferred out of the installation as pure substance, or directly used and bound in products or as feedstock, provided the subtraction is mirrored by a respective reduction for the activity and installation which the respective Member State reports in its national inventory submission to the Secretariat of the United Nations Framework Convention on Climate Change. The respective amount of CO2 shall be reported as a memo item. Respective installations are to be notified by Member States to the EU Commission under the obligations of Article 21 of Directive 2003/87/EC. Potential cases of ‘transferred CO2’ out of an installation include, inter alia:

— pure CO2 used for the carbonation of beverages,

— pure CO2 used as dry ice for cooling purposes,

— pure CO2 used as fire extinguishing agent, refrigerant or as laboratory gas,

— pure CO2 used for grains disinfestations,

— pure CO2 used as solvent in the food or chemical industry,

— CO2 used and bound in products or feedstocks in the chemical, pulp industry (e.g. for urea or precipitated carbonates),

— carbonates bound in spray-dried absorption product (SDAP) from semi-dry scrubbing of flue gases.

The mass of annually transferred CO2 or carbonate shall be determined with a maximum uncertainty of less than 1,5 % either directly by using volume or mass flow meters, weighing or indirectly from the mass of the respective product (e.g. carbonates or urea) where relevant and if appropriate.

In instances, in which part of the transferred CO2 was generated from biomass, or whenever an installation is only partially covered by Directive 2003/87/EC, the operator shall subtract only the respective fraction of mass of transferred CO2 which originates from fossil fuels and materials in activities covered by the Directive. Respective attribution methods shall be conservative and are subject to approval by the competent authority.

6. MEASUREMENT-BASED METHODOLOGIES

6.1. GENERAL

As set out in Section 4.2, greenhouse gas emissions may be determined by a measurement-based methodology using continuous emission measurement systems (CEMS) from all or selected emission sources using standardised or accepted methods once the operator has received approval from the competent authority before the reporting period that using a CEMS achieves greater accuracy than the calculation of emissions using the most accurate tier approach. Specific approaches for measurement based methodologies are laid down in Annex XII of these guidelines. Installations applying CEMS as part of their monitoring system are to be notified by Member States to the EU Commission pursuant to Article 21 of Directive 2003/87/EC.

The procedures applied for the measurement of concentrations, as well as for mass or volume flows shall, where available, be according to a standardised method that limits sampling and measurement bias and has a known measurement uncertainty. CEN standards (i.e. those issued by the European Committee for Standardisation) shall be used, if available. If CEN standards are not available, suitable ISO standards (i.e. those issued by the International Standardisation Organisation) or national standards shall apply. Where no applicable standards exist, procedures can be carried out where possible in accordance with suitable draft standards or industry best practice guidelines.

Relevant ISO standards include, inter alia:

— ISO 12039:2001 Stationary source emissions — Determination of carbon monoxide, carbon dioxide and oxygen — Performance characteristics and calibration of an automated measuring method,

— ISO 10396:2006 Stationary source emission — Sampling for the automated determination of gas concentrations,

— ISO 14164:1999 Stationary source emissions. Determination of the volume flow rate of gas streams in ducts — automated method.

The biomass fraction of measured CO2 emissions shall be subtracted based on the calculation approach and shall be reported as a memo item (see Section 14 of this Annex).

6.2. TIERS FOR MEASUREMENT-BASED METHODOLOGIES

The highest tier level pursuant to Annex XII shall be used by the operator of an installation for each emission source which is listed in the greenhouse gas emissions permit and for which relevant greenhouse gas emissions are determined applying CEMS.

Only if it is shown to the satisfaction of the competent authority that the highest tier approach is technically not feasible or will lead to unreasonably high costs, may a next lower tier be used for the relevant emission source. Therefore, the selected tier shall reflect for each emission source the highest level of accuracy that is technically feasible and does not lead to unreasonably high costs. The choice of tiers shall be subject to approval by the competent authority (see Section 4.3).

For the reporting periods 2008-2012 as a minimum Tier 2 in Annex XII shall be applied unless technically not feasible.

6.3. FURTHER PROCEDURES AND REQUIREMENTS

(a) Sampling rates

Hourly averages (a valid hour of data) shall be computed for all elements of the emission determination (as applicable) — as laid out in Annex XII — by using all data points available for that specific hour. In case of equipment being out of control or out of operation for part of the hour, the hourly average shall be calculated pro rata to the remaining data points for that specific hour. In case a valid hour of data cannot be computed for an element of emission determination, as less than 50 % of the maximum number of hourly data points (4) are available, the hour is lost. For each instance where a valid hour of data cannot be computed, values for substitution according to the provisions of this Section shall be calculated.

(b) Missing data

Where a valid hour of data cannot be provided for one or more elements of emission calculation due to the equipment being out of control (e.g. in case of calibration or interference errors) or out of operation, the operator shall determine values for substitution for each missing hour of data as shown below.

(i) Concentrations

In case a valid hour of data cannot be provided for a parameter directly measured as concentration (e.g. GHGs, O2), a substitution value C*subst for that hour shall be calculated as follows:

With:

the arithmetic mean of the concentration of the specific parameter,

σ C_ the best estimate of the standard deviation of the concentration of the specific parameter.

Arithmetic mean and standard deviation are to be calculated at the end of the reporting period from the whole set of emission data measured during the reporting period. If such a period is not applicable due to essential technical changes at the installation, a representative timeframe, if possible with a duration of one year, shall be agreed with the competent authority.

The calculation of arithmetic mean and standard deviation shall be presented to the verifier;

(ii) Other parameters

In case a valid hour of data cannot be provided for the parameters not directly measured as concentrations, substitute values of these parameters shall be obtained through a mass balance model or the energy balance approach of process. The remaining measured elements of emission calculation shall be used to validate the results.

The mass or energy balance model and underlying assumptions shall be clearly documented and presented to the verifier together with the calculated results.

(c) Corroborating calculation of emissions

Parallel to emission determination by a measurement based methodology, annual emissions of each considered GHG shall be determined by calculation based on one of the following options:

(a) calculation of emissions as laid down in the respective Annexes for the respective activities. For the calculation of emissions, lower tiers (i.e. Tier 1 as a minimum) can generally be applied or;

(b) calculation of emissions as laid down in the 2006 IPCC Guidelines, e.g. Tier 1 methods may be used.

Deviations between the results from the measurement and the calculation approach can occur. The operator shall explore the correlation between results from the measurement and the calculation approach, taking into account that a generic deviation resulting from the two different approaches might exist. Taking this correlation into account, the operator shall use the results of the calculation approach to cross-check results from the measurement approach.

The operator shall determine and report in the annual emission report, relevant data where available or best estimates of activity data, net calorific values, emission factors, oxidation factors and other parameters used for the determination of emissions according to Annexes II to XI — using laboratory analyses where appropriate. Respective approaches as well as the chosen method for the corroborating calculation shall be laid down in the monitoring plan and be approved by the competent authority.

Where comparison with results of the calculation approach clearly indicates that results of the measurement approach are not valid, the operator shall use substitution values as described under this Section.

7. UNCERTAINTY ASSESSMENT

7.1. CALCULATION

This Section is subject to Section 16 of this Annex. The operator shall have an understanding of main sources of uncertainty when calculating emissions.

Under the calculation-based methodology following the provisions of Section 5.2, the competent authority will have approved the combination of tiers for each source stream in an installation plus approved all other details of the monitoring methodology for that installation as contained within the installation's permit. In doing so, the competent authority has authorised the uncertainty directly resulting from correct application of the approved monitoring methodology, and the evidence of that approval is the content of the permit. Stating the combination of tiers in the emissions report shall constitute reporting uncertainty for the purposes of Directive 2003/87/EC. Hence there is no further requirement to report on uncertainty if the calculation-based methodology is applied.

The uncertainty determined for the measurement system within the tier system shall comprise the specified uncertainty of the applied measurement instruments, uncertainty associated with the calibration and any additional uncertainty connected to how the measurement instruments are used in practice. The stated threshold values within the tier system refer to the uncertainty associated to the value for one reporting period.

As regards commercially traded fuels or materials, competent authorities may permit the determination of the annual fuel/material flow by the operator based solely on the invoiced amount of fuel or material without further individual proof of associated uncertainties, provided that national legislation or the demonstrated application of relevant national or international standards ensures that respective uncertainty requirements for activity data are met for commercial transactions.

In all other cases, the operator shall provide written proof of the uncertainty level associated with the determination of activity data for each source stream in order to demonstrate compliance with the uncertainty thresholds defined in Annexes II-XI of these guidelines. The operator shall base the calculation on the specifications as provided by the supplier of the measurement instruments. If the specifications are not available, the operator shall provide for an uncertainty assessment of the measurement instrument. In both cases, he shall take into account necessary corrections of these specifications from effects resulting from the actual use conditions like ageing, conditions of the physical environment, calibration and maintenance. These corrections may involve conservative expert judgement.

If measurement systems are applied, the operator shall take into account the cumulative effect of all components of the measurement system on the uncertainty of the annual activity data using the error propagation law (5) which yields two convenient rules for combining uncorrelated uncertainties under addition and multiplication or respective conservative approximations if interdependent uncertainties occur:

(a) for uncertainty of a sum (e.g. of individual contributions to an annual value):

for uncorrelated uncertainties:

for interdependent uncertainties:

Where:

Utotal is the uncertainty of the sum, expressed as a percentage;

xi and Ui are the uncertain quantities and the percentage uncertainties associated with them, respectively;

(b) for uncertainty of a product (e.g. of different parameters used to convert a meter reading into mass flow data):

for uncorrelated uncertainties:

for interdependent uncertainties:

Where:

Utotal is the uncertainty of the product, expressed as a percentage;

Ui are the percentage uncertainties associated with each of the quantities.

The operator, via the quality assurance and control process, shall manage and reduce the remaining uncertainties of the emissions data in his emissions report. During the verification process, the verifier shall check the correct application of the approved monitoring methodology, and shall assess the management and reduction of remaining uncertainties via the operator's quality assurance and control procedures.

7.2. MEASUREMENT

As set out in Section 4.2, an operator can justify the use of measurement-based methodology if it reliably results in a lower uncertainty than the relevant calculation-based methodology (compare Section 4.2). In order to provide this justification to the competent authority, the operator shall report the quantitative results of a more comprehensive uncertainty analysis considering the following sources of uncertainty taking into account EN 14181.

— the specified uncertainty of continuous measurement equipment,

— uncertainties associated to the calibration,

— additional uncertainty connected to how the monitoring equipment is used in practice.

On the basis of the operator's justification, the competent authority may approve the operator's use of a continuous emission measurement system for selected or all emission sources in an installation plus approve all other details of the monitoring methodology for those emission sources, as to be contained within the installation's permit. In doing so, the competent authority has authorised the uncertainty directly resulting from correct application of the approved monitoring methodology, and the evidence of that approval is the content of the permit.

The operator shall state the uncertainty figure resulting from this initial comprehensive uncertainty analysis in his annual emissions report to the competent authority for the relevant emission sources and source streams, until such point that the competent authority reviews the choice of measurement over calculation and requests that the uncertainty figure be re-calculated. Stating this uncertainty figure in the emissions report shall constitute reporting uncertainty for the purposes of Directive 2003/87/EC.

The operator, via the quality assurance and control process, shall manage and reduce the remaining uncertainties of the emissions data in his emissions report. During the verification process, the verifier shall check the correct application of the approved monitoring methodology, and shall assess the management and reduction of remaining uncertainties via the operator's quality assurance and control procedures.

8. REPORTING

Annex IV to Directive 2003/87/EC sets out the reporting requirements for installations. The reporting format set out in Section 14 of this Annex and the information required therein shall be used as a basis for reporting of the quantitative data unless an equivalent electronic standard protocol for annual reporting has been published by the EU Commission.

The emission report covers annual emissions of a calendar year in a reporting period.

The report shall be verified in accordance with the detailed requirements established by the Member State pursuant to Annex V to Directive 2003/87/EC. The operator shall submit the verified report to the competent authority by 31 March each year for emissions during the preceding year.

Emission reports held by the competent authority shall be made available to the public by that authority subject to the rules laid down in Directive 2003/4/EC of the European Parliament and of the Council of 28 January 2003 on public access to environmental information and repealing Council Directive 90/313/EEC (6). With regard to the application of the exception laid down in Article 4(2)(d) of that Directive, operators may indicate in their report which information they consider commercially sensitive.

Each operator shall include the following information in the report for an installation:

(1) data identifying the installation, as specified in Annex IV to Directive 2003/87/EC, and its unique permit number;

(2) for all emissions sources and/or source streams the emission totals, chosen approach (measurement or calculation), chosen tiers and method (if applicable), activity data (7), emission factors (8), and oxidation/conversion factors (9). The following items, which are not accounted for in terms of emissions, shall be reported as memo items: amounts of biomass combusted [TJ] or employed in processes [t or Nm3]; CO2 emissions [tCO2] from biomass where measurement is used to determine emissions; CO2 transferred from an installation [tCO2]; inherent CO2 leaving the installation as part of a fuel;

(3) if emission factors and activity data for fuels are related to mass instead of energy, the operator shall report supplementary proxy data for the annual average net calorific value and emission factor for each fuel ‘proxy data’ means annual values — substantiated empirically or by accepted sources — used to substitute data for variables (i.e. fuel/material flow, net calorific value or emission, oxidation or conversion factors) required in the default calculation approaches according to Annexes I-XI in order to ensure complete reporting when the monitoring methodology does not generate all required variables;

(4) if a mass-balance approach is applied operators shall report the mass flow, carbon and energy content for each fuel and material stream into and out of the installation and their stocks;

(5) if continuous emissions monitoring (Annex XII) is applied, the operator shall report the annual fossil CO2 emissions as well the CO2 emissions from biomass use. In addition, the operator shall report supplementary proxy data for the annual average net calorific value and emission factor for each fuel or respective other relevant parameters for materials and products as derived by means of the corroborating calculation;

(6) if a fall-back approach according to Section 5.3 is applied, the operator shall report supplementary proxy data for every parameter for which the approach does not produce the required data according to Annexes I to XI;

(7) where fuel use occurs, but emissions are calculated as process emissions, the operator shall report supplementary proxy data for the respective variables of the default emission calculation for combustion emissions for these fuels;

(8) temporal or permanent changes of tiers, reasons for these changes, starting date for changes, and starting and ending dates of temporal changes;

(9) any other changes in the installation during the reporting period that may be relevant for the emissions report.

Information to be provided under (8) and (9) and supplementary information to be provided under (2) is not suitable for presentation in the tabulated form of the reporting format and shall therefore be included in the annual emission report as plain text.

Fuels and resulting emissions shall be reported using the IPCC fuel categories (see Section 11 of this Annex) which are based on the definitions of the International Energy Agency. In the event that the Member State relevant to the operator has published a list of fuel categories including definitions and emission factors consistent with its latest national inventory submitted to the Secretariat of the United Nations Framework Convention on Climate Change these categories and their emissions factors shall be used if approved under the relevant monitoring methodology.

In addition, waste types and emissions resulting from their use as fuels or input materials shall be reported. The waste types shall be reported using the classification of the Community list of wastes specified in Commission Decision 2000/532/EC of 3 May 2000 replacing Decision 94/3/EC establishing a list of wastes pursuant to Article 1(a) of Council Directive 75/442/EEC on waste and Council Decision 94/904/EC establishing a list of hazardous waste pursuant to Article 1(4) of Council Directive 91/689/EEC on hazardous waste (10). The respective six-digit codes shall be added to the names of the relevant waste types used in the installation.

Emissions occurring from different emission sources or source streams of the same type of a single installation belonging to the same type of activity may be reported in an aggregate manner for the type of activity.

Emissions shall be reported as rounded tonnes of CO2 (for example 1 245 978 tonnes). Activity data, emission factors and oxidation or conversion factors shall be rounded to include only significant digits both for emission calculations and reporting purposes.

In order to achieve consistency between data reported under Directive 2003/87/EC and data reported by Member States under the UN Framework Convention on Climate Change and other emission data reported for the European Pollutant Release and Transfer Register (EPRTR), each activity carried out by an installation shall be labelled applying the codes from the following two reporting schemes:

(a) the Common Reporting Format for national greenhouse gas inventory systems as approved by the respective bodies of the United Nations Framework Convention on Climate Change (see Section 15.1 of this Annex);

(b) the IPPC code of Annex I of Regulation 166/2006 on the European Pollutant Release and Transfer Register (EPRTR) (see Section 15.2 below).

9. RETENTION OF INFORMATION

An operator of an installation shall document and archive monitoring data for the installation's emissions from all emission sources and/or source streams belonging to activities listed in Annex I to Directive 2003/87/EC of greenhouse gases specified in relation to those activities.

The documented and archived monitoring data shall be sufficient to allow for the verification of the annual emissions report of an installation's emissions submitted by the operator pursuant to Article 14(3) of Directive 2003/87/EC, in accordance with the criteria set out in Annex V to that Directive.

Data that are not part of the annual emissions report shall not be required to be reported or made public otherwise.

To allow reproducibility of the determination of emissions by the verifier or another third party, an operator of an installation shall retain the following information for at least ten years after the submission of the report pursuant to Article 14(3) of Directive 2003/87/EC for each reporting year:

For calculation-based methodologies:

— the list of all source streams monitored,

— the activity data used for any calculation of the emissions for each source stream, categorised by process and fuel, or material type,

— documents justifying the selection of the monitoring methodology and the documents justifying temporal or non-temporal changes of monitoring methodologies and tiers approved by the competent authority,

— documentation of the monitoring methodology and results from the development of activity-specific emission factors and biomass fractions for specific fuels, and oxidation or conversion factors, and respective proofs of approval from the competent authority,

— documentation of the process of collection of activity data for the installation and its source streams,

— the activity data, emission, oxidation or conversion factors submitted to the competent authority for the national allocation plan for years preceding the time period covered by the trading scheme,

— documentation of the responsibilities in connection to the emissions monitoring,

— the annual emissions report, and

— any other information that is identified as required for the verification of the annual emissions report.

The following additional information shall be retained for measurement-based methodologies:

— the list of all emission sources monitored,

— documentation justifying the selection of a measurement-based methodology,

— the data used for the uncertainty analysis of emissions from each emission source, categorised by process,

— the data used for the corroborating calculations,

— a detailed technical description of the continuous measurement system including the documentation of the approval from the competent authority,

— raw and aggregated data from the continuous measurement system, including documentation of changes over time, the log-book on tests, down-times, calibrations, servicing and maintenance,

— documentation of any changes of the continuous measurement system.

10. CONTROL AND VERIFICATION

The control and verification of emissions is subject to Section 16 of this Annex.

10.1. DATA ACQUISITION AND HANDLING

The operator shall establish, document, implement and maintain effective data acquisition and handling activities (hereinafter referred to as data flow activities) for the monitoring and reporting of greenhouse gas emissions in accordance with the approved monitoring plan, the permit and these guidelines. These data flow activities include measuring, monitoring, analyzing, recording, processing and calculating parameters in order to be able to report on the greenhouse gas emissions.

10.2. CONTROL SYSTEM

The operator shall establish, document, implement and maintain an effective control system to ensure that the annual emissions report, resulting from the data flow activities does not contain misstatements and is in conformance with the approved monitoring plan, the permit and these guidelines.

The operator's control system is made up of the processes aimed at effective monitoring and reporting as designed and implemented by those in charge of annual emissions reporting. The control system consists of the following components:

(a) the operator's own assessment process of inherent and control risks to errors, misrepresentations or omissions (misstatements) in the annual emissions report, and non-conformities against the approved monitoring plan, the permit and these guidelines;

(b) control activities that help to mitigate the identified risks. The operator shall evaluate and improve his control system to ensure that the annual emissions report is not materially misstated or contains a material non-conformity. The evaluations shall include internal audits of the control system and the data reported. The control system may make reference to other procedures and documents, including those in management systems EU Eco-Management and Audit Scheme (EMAS), ISO 14001:2004 (Environmental management systems — Specification with guidance for use), ISO 9001:2000 and financial control systems. When such a reference has been made, the operator shall ensure that the requirements in the approved monitoring plan, the permit and these guidelines are arranged for in the respective applicable system.

10.3. CONTROL ACTIVITIES

For the purposes of controlling and mitigating the inherent and control risks pursuant to Chapter 10.2 the operator shall identify and implement control activities in accordance with the following Sections 10.3.1 to 10.3.6.

10.3.1. PROCEDURES AND RESPONSIBILITIES

The operator shall assign responsibilities to all data flow activities and to all control activities. Conflicting duties shall be segregated, including handling and control activities, where possible and otherwise alternative controls shall be put in place.

The operator shall document the data flow activities pursuant to Section 10.1 and the control activities pursuant to Sections 10.3.2 to 10.3.6 in written procedures, including:

— the sequence and interaction of data acquisition and handling activities according to 10.1, including the methods of calculations or measurement which are used,

— risk assessment of the definition and evaluations of the control system according to 10.2,

— management of the necessary competences for the responsibilities assigned according to 10.3.1,

— quality assurance of the measuring equipment and information technology used (if applicable) according to 10.3.2,

— internal reviews of reported data according to 10.3.3,

— outsourced processes according to 10.3.4,

— corrections and corrective action according to 10.3.5,

— records and documentation according to 10.3.6.

Each of these procedures shall address (where appropriate) the following elements:

— responsibilities,

— records (electronic and physical, whatever is applicable and suitable),

— information systems used (if applicable),

— input and output, and clear linkage with previous and next activity,

— frequency (if applicable).

The procedures shall be suitable to mitigate the identified risks.

10.3.2. QUALITY ASSURANCE

The operator shall ensure that relevant measuring equipment is calibrated, adjusted and checked at regular intervals including prior to use, and checked against measurement standards traceable to international measurement standards where available, in accordance with the risks identified according to 10.2. The operator shall identify in the monitoring plan if components of the measurement instrument cannot be calibrated, and propose alternative control activities, which need approval of the competent authority. When the equipment is found not to conform to requirements, the operator shall promptly take necessary remedial action. Records of the results of calibration and authentication shall be retained for the period of 10 years.

If the operator uses information technology, including process-control computer technology, it shall be designed, documented, tested, implemented, controlled and maintained as a way to ensure reliable, accurate and timely processing of data in accordance with the risks identified according to 10.2. This includes the proper use of calculation formulae contained in the monitoring plan. The control of information technology shall include access control, back up, recovery, continuity planning and security.

10.3.3. REVIEWS AND VALIDATION OF DATA

For managing the data flow, the operator shall design and implement reviews and validation of data in accordance with the risks identified according to 10.2. These validations may be conducted either manually or electronically. They shall be designed in such a way that boundaries for rejecting the data are clear upfront, where possible.

Simple and effective data reviews may be performed at the operational level by comparisons of monitored values using vertical and horizontal approaches.

A vertical approach compares emissions data monitored for the same installation in different years. A monitoring error is likely if differences between annual data cannot be explained by:

— changes in activity levels,

— changes concerning fuels or input material,

— changes concerning the emitting processes (e.g. energy efficiency improvements).

A horizontal approach compares values resulting from different operational data collection systems, including:

— comparison of fuel or material purchasing data with data on stock changes (based on information on end stock and begin stock) and data on consumption for the applicable source streams,

— comparison of emission factors that have been analysed, calculated or obtained from the fuel supplier, to national or international reference emission factors of comparable fuels,

— comparison of emission factors based on fuel analyses to national or international reference emission factors of comparable fuels,

— comparison of measured and calculated emissions.

10.3.4. OUTSOURCED PROCESSES

Where an operator chooses to outsource any process in the data flow, the operator shall control the quality of these processes in accordance with the risks identified according to 10.2. The operator shall define appropriate requirements for outputs and methods, and review the quality delivered.

10.3.5. CORRECTIONS AND CORRECTIVE ACTION

When any part of the data flow activities or control activities (device, equipment, staff member, supplier, procedure or other) is found not to function effectively or to function outside set boundaries, the operator shall promptly take appropriate corrections and the rejected data shall be corrected. The operator shall assess the validity of the outputs of the applicable steps, determine the root cause of the malfunctioning or error, and take appropriate corrective action.

The activities in this Section shall be performed in accordance with the risk-based approach according to 10.2.

10.3.6. RECORDS AND DOCUMENTATION

To be able to show and ensure compliance, and to be able to reconstruct emissions data reported, the operator shall keep records of all control activities (including quality assurance/quality control of equipment and information technology, review and validation of data and corrections) and all information listed under Section 9 of this Annex for at least 10 years.

The operator shall ensure that relevant documents are available when and where they are needed to perform the data flow activities as well as the control activities. The operator shall have a procedure to identify, produce, distribute and control the version of these documents.

The activities in this Section shall be performed in accordance with the risk-based approach according to 10.2.

10.4. VERIFICATION

10.4.1. GENERAL PRINCIPLES

The objective of the verification is to ensure that emissions have been monitored in accordance with the guidelines and that reliable and correct emissions data will be reported pursuant to Article 14(3) of Directive 2003/87/EC. Member States shall consider respective guidance issued by the European Cooperation for Accreditation (EA).

Subject to Chapter 10.4.2(e), a verification shall come to a verification opinion that states with reasonable assurance whether the data in the emissions report is free from material misstatements and whether there are no material non-conformities.

The operator shall submit the emissions report, a copy of its approved monitoring plan for each of its installations, and any other relevant information to the verifier.

The scope of the verification is defined by the tasks the verifier needs to perform to achieve the above objective. As a minimum the verifier shall perform the activities in accordance with the subsequent Section 10.4.2.

10.4.2. VERIFICATION METHODOLOGY

The verifier shall plan and perform verification with an attitude of professional scepticism recognizing that circumstances may exist that cause the information contained in the Annual Emissions Report to be materially misstated.

As part of the verification process, the verifier shall carry out the following steps:

(a) strategic analysis

The verifier shall:

— verify whether the monitoring plan has been approved by the competent authority and whether it is the right version. If this is not the case, the verifier should not continue the verification except for elements that are obviously not affected by the non-approval,

— understand each activity undertaken by the installation, the sources, source streams within the installation, the metering equipment used to monitor or measure activity data, the origin and application of emission factors and oxidation/conversion factors, any other data used to calculate or measure the emissions, and the environment in which the installation operates,

— understand the operator's monitoring plan, data flow, as well as its control system, including the overall organisation with respect to monitoring and reporting,

— apply the materiality level defined in Table 3 below. Table 3 Materiality levels Materiality level Category A and B installations 5 % Category C installations 2 %

The verifier shall perform the strategic analysis in such a way that the verifier is able to conduct the risk analysis as set out below. When necessary this shall include a site visit.

(b) risk analysis

The verifier shall:

— analyse the inherent risks and control risks related to the scope and complexity of the operator's activities and emission sources and source streams, and which could lead to a material misstatements and non-conformities,

— draw up a verification plan which is commensurate with this risk analysis. The verification plan describes the way in which the verification activities are to be carried out. It contains a verification programme and a data sampling plan. The verification programme describes the nature of the activities, at what times they must be carried out and their scope in order for the verification plan to be completed. The data sampling plan sets out what data is to be tested in order to reach a verification opinion.

(c) verification

In carrying out the verification, the verifier shall conduct a site visit, when appropriate, to inspect the operation of meters and monitoring systems, conduct interviews, and collect sufficient information and evidence.

Moreover, the verifier shall:

— carry out the verification plan by gathering data in accordance with the defined sampling methods, walkthrough tests, document reviews, analytical procedures and data review procedures, including any relevant additional evidence, upon which the verifier's verification opinion will be based,

— confirm the validity of the information used to calculate the uncertainty level as set in the approved monitoring plan,

— verify that the approved monitoring plan is implemented and seek understanding whether the monitoring plan is up to date,

— request the operator to provide any missing data or complete missing sections of audit trails, explain variations in the emissions data, or revise calculations, or adjust reported data, before reaching a final verification opinion. The verifier should, in any form, report all non-conformities and misstatements identified to the operator.

The operator shall correct any reported misstatements. The entire population from which a sample was taken shall be corrected.

Throughout the verification process, the verifier shall determine misstatements and non-conformities by assessing whether:

— the monitoring plan has been implemented to support the determination of non-conformities,

— there is clear and objective evidence obtained through the gathering of data to support the determination of misstatements.

(d) internal verification report

At the end of the verification process, the verifier shall prepare an internal verification report. The verification report shall record evidence showing that the strategic analysis, the risk analysis and the verification plan has been performed in full, and provide sufficient information to support verification opinions. The internal verification report should as well facilitate a potential evaluation of the audit by the competent authority and accreditation body.

Based on the findings contained in the internal verification report, the verifier shall make a judgment with respect to whether the annual emissions report contains any material misstatement as compared to the materiality threshold, and whether there are material non-conformities or other issues relevant for the verification opinion.

(e) verification report

The verifier shall present the verification methodology, his findings and verification opinion in a verification report, addressed to the operator, to be submitted by the operator with the annual emission report to the competent authority. An annual emissions report is verified as satisfactory if the total emissions are not materially misstated, and if, in the opinion of the verifier, there are no material non-conformities. In the case of non-material non-conformities or non-material misstatements, the verifier may include these in the verification report (verified as satisfactory with non-material non-conformities or non-material misstatements). The verifier may also report these in a separate management letter.

The verifier may conclude an annual emissions report is not verified as satisfactory, if the verifier finds material non-conformities or material misstatements (with or without material non-conformities). The verifier may conclude an annual emissions report is not verified when there was a limitation of scope (when circumstances prevent, or a restriction was imposed that prevents, the verifier from obtaining evidence required to reduce the verification risk to the reasonable level) and/or material uncertainties.

Member States shall ensure that the operator addresses non-conformities and misstatements after consultation of the competent authority in a timeframe set by the competent authority. In addition, all divergences of opinion between operators, verifiers and competent authorities shall not affect proper reporting and shall be settled in accordance with Directive 2003/87/EC, these guidelines, and the requirements established by the Member States pursuant to Annex V to that Directive, and relevant national procedures.

11. EMISSION FACTORS

This Section contains reference emission factors for the Tier 1 level that permit the use of non-activity-specific emission factors for the combustion of fuel. If a fuel does not belong to an existing fuel category the operator shall use his expert judgement to assign the fuel used to a related fuel category, subject to the approval of the competent authority.

Table 4

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

Fuel type description Emission factor (tCO2/TJ) Net calorific value (TJ/Gg) 2006 IPCC guidelines (except biomass) 2006 IPCC guidelines Crude oil 73,3 42,3 Orimulsion 76,9 27,5 Natural gas liquids 64,1 44,2 Motor gasoline 69,2 44,3 Kerosene 71,8 43,8 Shale oil 73,3 38,1 Gas/diesel oil 74,0 43,0 Residual fuel oil 77,3 40,4 Liquefied petroleum gases 63,0 47,3 Ethane 61,6 46,4 Naphtha 73,3 44,5 Bitumen 80,6 40,2 Lubricants 73,3 40,2 Petroleum coke 97,5 32,5 Refinery feedstocks 73,3 43,0 Refinery gas 51,3 49,5 Paraffin waxes 73,3 40,2 White spirit and SBP 73,3 40,2 Other petroleum products 73,3 40,2 Anthracite 98,2 26,7 Coking coal 94,5 28,2 Other bituminous coal 94,5 25,8 Sub-bituminous coal 96,0 18,9 Lignite 101,1 11,9 Oil shale and tar sands 106,6 8,9 Patent fuel 97,5 20,7 Coke oven coke and lignite coke 107,0 28,2 Gas coke 107,0 28,2 Coal tar 80,6 28,0 Gas works gas 44,7 38,7 Coke oven gas 44,7 38,7 Blast furnace gas 259,4 2,5 Oxygen steel furnace gas 171,8 7,1 Natural gas 56,1 48,0 Industrial wastes 142,9 n.a. Waste oils 73,3 40,2 Peat 105,9 9,8 Wood/wood waste 0 15,6 Other primary solid biomass 0 11,6 Charcoal 0 29,5 Biogasoline 0 27,0 Biodiesels 0 27,0 Other liquid biofuels 0 27,4 Landfill gas 0 50,4 Sludge gas 0 50,4 Other biogas 0 50,4 Other sources Other sources Waste tyres 85,0 n.a. Carbon monoxide 155,2 10,1 Methane 54,9 50,0

12. LIST OF CO2-NEUTRAL BIOMASS

This list contains materials, which are considered biomass for the application of these guidelines and shall be weighted with an emission factor of 0 [tCO2/TJ or t or Nm3]. Peat and fossil fractions of the materials listed below shall not be considered biomass. Unless a contamination with other materials or fuels is apparent based on visual or olfactory evidence, no analytical procedures need to be applied to demonstrate the purity of members of Group 1 and 2 below:

Group 1 — Plants and parts of plants:

— straw,

— hay and grass,

— leaves, wood, roots, stumps, bark,

— crops, e.g. maize and triticale.

Group 2 — Biomass wastes, products and by-products:

— industrial waste wood (waste wood from woodworking and wood processing operations and waste wood from operations in the wood materials industry),

— used wood (used products made from wood, wood materials) and products and by-products from wood processing operations,

— wood-based waste from the pulp and paper industries, e.g. black liquor (with only biomass carbon),

— crude tall oil, tall oil and pitch oil from the production of pulp,

— forestry residues,

— lignin from the processing of plants containing ligno-celluose,

— animal, fish and food meal, fat, oil and tallow,

— primary residues from the food and beverage production,

— plant oils and fats,

— manure,

— agricultural plant residues,

— sewage sludge,

— biogas produced by digestion, fermentation or gasification of biomass,

— harbour sludge and other waterbody sludges and sediments,

— landfill gas,

— charcoal.

Group 3 — Biomass fractions of mixed materials:

— the biomass fraction of flotsam from waterbody management,

— the biomass fraction of mixed residues from food and beverage production,

— the biomass fraction of composites containing wood,

— the biomass fraction of textile wastes,

— the biomass fraction of paper, cardboard, pasteboard,

— the biomass fraction of municipal and industrial waste,

— the biomass fraction of black liquor containing fossil carbon,

— the biomass fraction of processed municipal and industrial wastes,

— the biomass fraction of ethyl-tertiary-butyl-ether (ETBE),

— the biomass fraction of butanol.

Group 4 — Fuels whose components and intermediate products have all been produced from biomass:

— bioethanol,

— biodiesel,

— etherised bioethanol,

— biomethanol,

— biodimethylether,

— bio-oil (a pyrolysis oil fuel) and bio-gas.

13. DETERMINATION OF ACTIVITY-SPECIFIC DATA AND FACTORS

This Section is mandatory only for those parts of these guidelines with explicit reference to Section 13 of Annex I. The provisions in this Section are subject to those set out in Section 16 of this Annex.

13.1. DETERMINATION OF NET CALORIFIC VALUES AND EMISSION FACTORS FOR FUELS

The specific procedure to determine the activity specific emission factor including the sampling procedure for a specific fuel type shall be agreed with the competent authority before the start of respective reporting period in which it will be applied.

The procedures applied to sample the fuel and to determine its net calorific value, carbon content and emission factor shall, where available, be according to a standardised method that limits sampling and measurement bias and has a known measurement uncertainty. CEN standards shall be used if available. If CEN standards are not available, suitable ISO standards or national standards shall apply. Where no applicable standards exist, procedures can be carried out where possible in accordance with suitable draft standards or industry best practice guidelines.

Relevant CEN standards are the following:

— EN ISO 6976:2005 Natural gas — Calculation of calorific values, density, relative density, and Wobbe index from composition,

— EN ISO 4259:1996 Petroleum products — Determination and application of precision data in relation to methods of test.

Relevant ISO standards are the following:

— ISO 13909-1,2,3,4:2001 Hard coal and coke — Mechanical sampling,

— ISO 5069-1,2:1983 Brown coals and lignites — Principles of sampling,

— ISO 625:1996 Solid mineral fuels — Determination of carbon and hydrogen — Liebig method,

— ISO 925:1997 Solid mineral fuels — Determination of carbonate carbon content — Gravimetric method,

— ISO 9300:1990 Measurement of gas flow by means of critical flow Venturi nozzles,

— ISO 9951:1993/94 Measurement of gas flow in closed conduits — Turbine meters.

Supplemental national standards for the characterization of fuels are as follows:

— DIN 51900-1:2000 Testing of solid and liquid fuels — Determination of gross calorific value by the bomb calorimeter and calculation of net calorific value — Part 1: Principles, apparatus, methods,

— DIN 51857:1997 Gaseous fuels and other gases — Calculation of calorific value, density, relative density and Wobbe index of pure gases and gas mixtures,

— DIN 51612:1980 Testing of liquefied petroleum gases, calculation of net calorific value,

— DIN 51721:2001 Testing of solid fuels — Determination of carbon and hydrogen content (also applicable for liquid fuels).

The laboratory used to determine the emission factor, carbon content and net calorific value shall comply with requirements laid down in Section 13.5 of this Annex. It is important to note that to achieve appropriate accuracy of the activity specific emission factor (in addition to the precision of the analytical procedure for the determination of the carbon content and the net calorific value) the sampling frequency, the sampling procedure and the sample preparation are critical. They depend greatly on the state and homogeneity of the fuel/material. The required number of samples will be larger for very heterogeneous materials such as municipal solid waste and be much smaller for most commercial gaseous or liquid fuels.

The sampling procedure and frequency of analyses for the determination of the carbon content, net calorific values and emission factors shall comply with the requirements of Section 13.6.

The full documentation of the procedures used in the respective laboratory for the determination of the emission factor and the full set of results shall be retained and made available to the verifier of the emissions report.

13.2. DETERMINATION OF ACTIVITY-SPECIFIC OXIDATION FACTORS

The specific procedure to determine the activity-specific oxidation factor including the sampling procedure for a specific fuel type and installation shall be agreed with the competent authority before the start of respective reporting period in which it will be applied.

The procedures applied to determine a representative activity-specific oxidation factors (e.g. via the carbon content of soot, ashes, effluents and other wastes or by-products) for a specific activity shall, where available, be according to a standardised method that limits sampling and measurement bias and has a known measurement uncertainty. CEN standards shall be used if available. If CEN standards are not available, suitable ISO standards or national standards shall apply. Where no applicable standards exist, procedures can be carried out where possible in accordance with suitable draft standards or industry best practice guidelines.

The laboratory used to determine the oxidation factor or the underlying data shall comply with requirements set out in Section 13.5 of this Annex. The sampling procedure and frequency of analyses for the determination of relevant variables (e.g. the carbon content of ash) used for the calculation of oxidation factors shall comply with the requirements of Section 13.6.

The full documentation of the procedures used by the organisation for the determination of the oxidation factor and the full set of results shall be retained and made available to the verifier of the emissions report.

13.3. DETERMINATION OF PROCESS EMISSION FACTORS, CONVERSION FACTORS AND COMPOSITION DATA

The specific procedure to determine the activity-specific emission factor, conversion factor or composition data including the sampling procedure for a specific material shall be agreed with the competent authority before the start of respective reporting period in which it will be applied.

The procedures applied to sample and determine the composition of the relevant material or derive a process emission factor shall, where available, be according to a standardised method that limits sampling and measurement bias and has a known measurement uncertainty. CEN standards shall be used if available. If CEN standards are not available suitable ISO standards or national standards shall apply. Where no applicable standards exist, procedures can be carried out where possible in accordance with suitable draft standards or industry best practice guidelines.

The laboratory used shall comply with requirements laid down in Section 13.5 of this Annex. The sampling procedure and frequency of analyses shall comply with the requirements of Section 13.6.

The full documentation of the procedures used by the organisation and the full set of results shall be retained and made available to the verifier of the emissions report.

13.4. DETERMINATION OF A BIOMASS FRACTION

The term ‘biomass fraction’ for the purpose of these guidelines refers to the mass percentage of biomass carbon according to the biomass definition (see Sections 2 and 12 of this Annex) out of the total mass of carbon in a sample.

Fuel or material shall qualify as pure biomass with simplified provisions for the monitoring and reporting as set out in Section 5.2, if the non-biomass content accounts to no more than 3 % of the total quantity of the fuel or material concerned.

The specific procedure to determine the biomass fraction of a specific fuel or material including the sampling procedure shall be agreed with the competent authority before the start of the reporting period in which it will be applied.

The procedures applied to sample the fuel or material and to determine the biomass fraction shall, where available, be according to a standardised method that limits sampling and measurement bias and has a known measurement uncertainty. CEN standards shall be used if available. If CEN standards are not available suitable ISO standards or national standards shall apply. Where no applicable standards exist, procedures can be carried out where possible in accordance with suitable draft standards or industry best practice guidelines.

Methods applicable to determine the biomass fraction in a fuel or material could range from the manual sorting of components of mixed materials, to differential methods determining heating values of a binary mixture and its two pure components to an isotopic analysis of carbon-14 — depending on the specific nature of the respective fuel mixture. For fuels or materials originating from a production process with defined and traceable input streams, the operator may alternatively base the determination of the biomass fraction on a mass-balance of fossil and biomass carbon entering and leaving the process. The respective methods are to be approved by the competent authority.

The laboratory used to determine the biomass fraction shall comply with requirements laid down in Section 13.5 of this Annex.

The sampling procedure and frequency of analyses for the determination of the biomass fraction of fuels and materials shall comply with the requirements of Section 13.6.

The full documentation of the procedures used in the respective laboratory for the determination of the biomass fraction and the full set of results sh