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Document 02018R2066-20240701
Commission Implementing Regulation (EU) 2018/2066 of 19 December 2018 on the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council and amending Commission Regulation (EU) No 601/2012 (Text with EEA relevance)Text with EEA relevance
Consolidated text: Commission Implementing Regulation (EU) 2018/2066 of 19 December 2018 on the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council and amending Commission Regulation (EU) No 601/2012 (Text with EEA relevance)Text with EEA relevance
Commission Implementing Regulation (EU) 2018/2066 of 19 December 2018 on the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council and amending Commission Regulation (EU) No 601/2012 (Text with EEA relevance)Text with EEA relevance
ELI: http://data.europa.eu/eli/reg_impl/2018/2066/2024-07-01
This consolidated text may not include the following amendments:
| Amending act | Amendment type | Subdivision concerned | Date of effect |
|---|---|---|---|
| 32024R2493 | Modified by | article 15 paragraph 4 point (b) | 01/01/2025 |
| 32024R2493 | Modified by | article 49 paragraph 7 | 01/01/2025 |
| 32024R2493 | Modified by | annex I section 1 point 7 point (f) | 01/01/2025 |
| 32024R2493 | Modified by | article 58 paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | article 4 | 01/01/2025 |
| 32024R2493 | Modified by | annex IX section 2 point 8 | 01/01/2025 |
| 32024R2493 | Modified by | article 72 paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | article 49a | 01/01/2025 |
| 32024R2493 | Modified by | annex I section 2 point 1 point (q) | 01/01/2025 |
| 32024R2493 | Modified by | article 68 paragraph 5 | 01/01/2025 |
| 32024R2493 | Modified by | article 14 paragraph 2 point (aa) | 01/01/2025 |
| 32024R2493 | Modified by | annex I section 4 point 3 | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 21 point A unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | article 11 paragraph 1 unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | annex V table 1 Text | 01/01/2025 |
| 32024R2493 | Modified by | annex IX section 3 point 5 | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 23 point A unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 23 point B.1 unnumbered paragraph 2 | 01/01/2025 |
| 32024R2493 | Modified by | annex X section 2a | 01/01/2025 |
| 32024R2493 | Modified by | article 6 paragraph 3 | 01/01/2025 |
| 32024R2493 | Modified by | annex I section 2 point 1 point (c) | 01/01/2025 |
| 32024R2493 | Modified by | article 49 paragraph 6 | 01/01/2025 |
| 32024R2493 | Modified by | article 49 paragraph 4 | 01/01/2025 |
| 32024R2493 | Modified by | chapter IV title | 01/01/2025 |
| 32024R2493 | Modified by | article 58 paragraph 2 point (c) | 01/01/2025 |
| 32024R2493 | Modified by | annex IIIb | 01/01/2025 |
| 32024R2493 | Modified by | article 8 | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 21 point B | 01/01/2025 |
| 32024R2493 | Modified by | article 49 paragraph 3 | 01/01/2025 |
| 32024R2493 | Modified by | annex I section 2 point 1 point (p) | 01/01/2025 |
| 32024R2493 | Modified by | annex V table 1 Text | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 23 point B.2 unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | annex IX section 2 point 7 point (b) | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 10 point A unnumbered paragraph 2 | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 23 point B unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | article 56b | 01/01/2025 |
| 32024R2493 | Modified by | article 52 paragraph 1 unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | annex II section 1 table 1 Text | 01/01/2025 |
| 32024R2493 | Modified by | article 56a | 01/01/2025 |
| 32024R2493 | Modified by | article 70 paragraph 1 unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | annex IX section 2 point 6 Text | 01/01/2025 |
| 32024R2493 | Modified by | annex IX section 3 point 6 | 01/01/2025 |
| 32024R2493 | Modified by | article 44 paragraph 1 unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | article 51 paragraph 1 unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | article 52 paragraph 1 unnumbered paragraph 2 | 01/01/2025 |
| 32024R2493 | Modified by | article 70 paragraph 2 | 01/01/2025 |
| 32024R2493 | Modified by | annex I section 1 point 8 | 01/01/2025 |
| 32024R2493 | Modified by | article 49 paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 7 point A unnumbered paragraph 1 | 01/01/2025 |
| 32024R2493 | Modified by | annex II section 1 table 1 Text | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 7 point A unnumbered paragraph 2 | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 20 point B | 01/01/2025 |
| 32024R2493 | Modified by | annex IV section 7 title | 01/01/2025 |
| 32024R2493 | Modified by | article 68 paragraph 6 | 01/01/2025 |
| 32024R2493 | Modified by | annex IIIa | 01/01/2025 |
02018R2066 — EN — 01.07.2024 — 005.001
This text is meant purely as a documentation tool and has no legal effect. The Union's institutions do not assume any liability for its contents. The authentic versions of the relevant acts, including their preambles, are those published in the Official Journal of the European Union and available in EUR-Lex. Those official texts are directly accessible through the links embedded in this document
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COMMISSION IMPLEMENTING REGULATION (EU) 2018/2066 of 19 December 2018 on the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council and amending Commission Regulation (EU) No 601/2012 (OJ L 334 31.12.2018, p. 1) |
Amended by:
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Official Journal |
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No |
page |
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COMMISSION IMPLEMENTING REGULATION (EU) 2020/2085 of 14 December 2020 |
L 423 |
37 |
15.12.2020 |
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COMMISSION IMPLEMENTING REGULATION (EU) 2022/388 of 8 March 2022 |
L 79 |
1 |
9.3.2022 |
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COMMISSION IMPLEMENTING REGULATION (EU) 2022/1371 of 5 August 2022 |
L 206 |
15 |
8.8.2022 |
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COMMISSION IMPLEMENTING REGULATION (EU) 2023/2122 of 12 October 2023 |
L 2122 |
1 |
18.10.2023 |
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COMMISSION IMPLEMENTING REGULATION (EU) 2018/2066
of 19 December 2018
on the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council and amending Commission Regulation (EU) No 601/2012
(Text with EEA relevance)
CHAPTER I
GENERAL PROVISIONS
SECTION 1
Subject matter and definitions
Article 1
Subject matter
This Regulation lays down rules for the monitoring and reporting of greenhouse gas emissions and activity data pursuant to Directive 2003/87/EC in the trading period of the Union emissions trading system commencing on 1 January 2021 and subsequent trading periods.
Article 2
This Regulation shall apply to the monitoring and reporting of greenhouse gas emissions specified in relation to the activities listed in Annexes I and III to Directive 2003/87/EC, to activity data from stationary installations, to aviation activities and to released fuel amounts from activities referred to in Annex III to that Directive.
It shall apply to emissions, activity data and released fuel amounts occurring from 1 January 2021.
Article 3
Definitions
For the purposes of this Regulation, the following definitions shall apply:
‘activity data’ means data on the amount of fuels or materials consumed or produced by a process relevant for the calculation-based monitoring methodology, expressed in terajoules, mass in tonnes or (for gases) volume in normal cubic metres, as appropriate;
‘trading period’ means a period as referred to in Article 13 of Directive 2003/87/EC;
▼M4 —————
‘source stream’ means any of the following:
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;
a specific fuel type, raw material or product containing carbon and included in the calculation of greenhouse gas emissions using a mass-balance methodology;
‘emission source’ means a separately identifiable part of an installation or a process within an installation, from which relevant greenhouse gases are emitted or, for aviation activities, an individual aircraft;
‘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, 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;
‘calculation factors’ means net calorific value, emission factor, preliminary emission factor, oxidation factor, conversion factor, carbon content, biomass fraction or unit conversion factor;
‘tier’ means a set requirement used for determining activity data, calculation factors, annual emission and annual average hourly emission, released fuel amount and scope factor;
‘inherent risk’ means the susceptibility of a parameter in the annual emissions report to misstatements that could be material, individually or when aggregated with other misstatements, before taking into consideration the effect of any related control activities;
‘control risk’ means the susceptibility of a parameter in the annual emissions report to misstatements that could be material, individually or when aggregated with other misstatements, and not prevented or detected and corrected on a timely basis by the control system;
‘combustion emissions’ means greenhouse gas emissions occurring during the exothermic reaction of a fuel with oxygen;
‘reporting period’ means a calendar year during which emissions have to be monitored and reported;
‘emission factor’ means the average emission rate of a greenhouse gas relative to the activity data of a source stream or a fuel stream assuming complete oxidation for combustion and complete conversion for all other chemical reactions;
‘oxidation factor’ means the ratio of carbon oxidised to CO2 as a consequence of combustion to the total carbon contained in the fuel, expressed as a fraction, considering carbon monoxide (CO) emitted to the atmosphere as the molar equivalent amount of CO2;
‘conversion factor’ means the ratio of carbon emitted as CO2 to the total carbon contained in the source stream before the emitting process takes place, expressed as a fraction, considering CO emitted to the atmosphere as the molar equivalent amount of CO2;
‘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;
‘calibration’ means the set of operations, which establishes, 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;
‘flight’ means flight as defined in point 1(1) of the Annex to Decision 2009/450/EC;
‘passengers’ means the persons onboard the aircraft during a flight excluding its on duty crew members;
‘conservative’ means that a set of assumptions is defined in order to ensure that no under-estimation of annual emissions occurs;
‘biomass’ means the biodegradable fraction of products, waste and residues from biological origin from agriculture, including vegetal and animal substances, from forestry and related industries, including fisheries and aquaculture, as well as the biodegradable fraction of waste, including industrial and municipal waste of biological origin;
‘biomass fuels’ means gaseous and solid fuels produced from biomass;
‘biogas’ means gaseous fuels produced from biomass;
‘waste’ means waste as defined in point (1) of Article 3 of Directive 2008/98/EC, excluding substances that have been intentionally modified or contaminated in order to meet this definition;
‘municipal waste’ means municipal waste as defined in Article 3, point (2b), of Directive 2008/98/EC;
‘residue’ means a substance that is not the end product(s) that a production process directly seeks to produce; it is not a primary aim of the production process and the process has not been deliberately modified to produce it;
‘agricultural, aquaculture, fisheries and forestry residues’ means residues that are directly generated by agriculture, aquaculture, fisheries and forestry and that do not include residues from related industries or processing;
‘bioliquids’ means liquid fuel for energy purposes other than for transport, including electricity and heating and cooling, produced from biomass;
‘biofuels’ means liquid fuels for transport produced from biomass;
‘eligible aviation fuel’ means fuel types eligible for the support under Article 3c(6) of Directive 2003/87/EC;
‘legal metrological control’ means the control of the measurement tasks intended for the field of application of a measuring instrument, for reasons of public interest, public health, public safety, public order, protection of the environment, the levying of taxes and duties, the protection of consumers and fair trading;
‘maximum permissible error’ means the error of measurement allowed as specified in Annex I and instrument-specific annexes to Directive 2014/32/EU of the European Parliament and of the Council ( 1 ), or national rules on legal metrological control, as appropriate;
‘data-flow activities’ mean activities related to the acquisition, processing and handling of data that are needed to draft an emissions report from primary source data;
‘tonnes of CO2(e)’ means metric tonnes of CO2 or CO2(e);
‘CO2(e)’ means any greenhouse gas, other than CO2, listed in Annex II to Directive 2003/87/EC with an equivalent global-warming potential as CO2;
‘measurement system’ means a complete set of measuring instruments and other equipment, such as sampling and data-processing equipment, used to determine variables such as the activity data, the carbon content, the calorific value or the emission factor of the greenhouse gas emissions;
‘net calorific value’ (NCV) means the specific amount of energy released as heat when a fuel or material undergoes complete combustion with oxygen under standard conditions, less the heat of vaporisation of any water formed;
‘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;
‘commercial standard fuel’ means the internationally standardised commercial fuels that 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, butane, jet kerosene (jet A1 or jet A), jet gasoline (jet B) and aviation gasoline (AvGas);
‘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;
‘mixed fuel’ means a fuel which contains both biomass and fossil carbon;
‘mixed aviation fuel’ means a fuel which contains both eligible aviation fuel and fossil fuel;
‘mixed material’ means a material which contains both biomass and fossil carbon;
‘preliminary emission factor’ means the assumed total emission factor of a fuel or material based on the carbon content of its biomass fraction and its fossil fraction before multiplying it by the fossil fraction to produce the emission factor;
‘fossil fraction’ means the ratio of fossil carbon to the total carbon content of a fuel or material, expressed as a fraction;
‘biomass fraction’ means the ratio of carbon stemming from biomass to the total carbon content of a fuel or material, expressed as a fraction;
‘eligible fraction’ means the ratio of eligible aviation fuel blended in the fossil fuel;
‘energy balance method’ means a method to estimate the amount of energy used as fuel in a boiler, calculated as the sum of utilisable heat and all relevant losses of energy by radiation, transmission and via the flue gas;
‘continuous emission measurement’ means a set of operations having the objective of determining the value of a quantity by means of periodic measurements, applying either measurements in the stack or extractive procedures with a measuring instrument located close to the stack, whilst excluding measurement methodologies based on the collection of individual samples from the stack;
‘inherent CO2’ means CO2 which is part of a source stream;
‘fossil carbon’ means inorganic and organic carbon that is not biomass;
‘measurement point’ means the emission source for which continuous emission measurement systems (CEMS) are used for emission measurement, or the cross-section of a pipeline system for which the CO2 flow is determined using continuous measurement systems;
‘mass and balance documentation’ means the documentation specified in international or national implementation of the standards and recommended practices (SARPs) laid down in Annex 6 to the Convention on International Civil Aviation, signed in Chicago on 7 December 1944 and specified in Section 3 of Subpart C of Annex IV to Commission Regulation (EU) No 965/2012 ( 2 ), or equivalent applicable international rules;
‘distance’ means the great-circle distance between the aerodrome of departure and the aerodrome of arrival, in addition to a fixed factor of 95 km;
‘aerodrome of departure’ means the aerodrome at which a flight constituting an aviation activity listed in Annex I to Directive 2003/87/EC begins;
‘aerodrome of arrival’ means the aerodrome at which a flight constituting an aviation activity listed in Annex I to Directive 2003/87/EC ends;
▼M4 —————
‘fugitive emissions’ means irregular or unintended emissions from sources that are not localised, or too diverse or too small to be monitored individually;
‘aerodrome’ means aerodrome as defined in point 1(2) of the Annex to Decision 2009/450/EC;
‘aerodrome pair’ means a pair constituted by the aerodrome of departure and the aerodrome of arrival;
‘standard conditions’ means temperature of 273,15 K and pressure conditions of 101 325 Pa defining normal cubic metres (Nm3);
‘storage site’ means storage site as defined in Article 3(3) of Directive 2009/31/EC;
‘CO2 capture’ means the activity of capturing from gas streams CO2 that would otherwise be emitted, for the purposes of transport and geological storage in a storage site permitted under Directive 2009/31/EC;
‘CO2 transport’ means the transport of CO2 by pipelines for geological storage in a storage site permitted under Directive 2009/31/EC;
‘geological storage of CO2’ means geological storage of CO2 as defined in Article 3(1) of Directive 2009/31/EC;
‘vented emissions’ means emissions deliberately released from an installation by provision of a defined point of emission;
‘enhanced hydrocarbon recovery’ means the recovery of hydrocarbons in addition to those extracted by water injection or other means;
‘proxy data’ means annual values which are empirically substantiated or derived from accepted sources and which an operator or regulated entity as defined in Article 3 of Directive 2003/87/EC uses to substitute the activity data, the released fuel amounts or the calculation factors for the purpose of ensuring complete reporting when it is not possible to generate all the required activity data, released fuel amounts or calculation factors in the applicable monitoring methodology;
‘water column’ means water column as defined in Article 3(2) of Directive 2009/31/EC;
‘leakage’ means leakage as defined in Article 3(5) of Directive 2009/31/EC;
‘storage complex’ means storage complex as defined in Article 3(6) of Directive 2009/31/EC;
‘transport network’ means transport network as defined in Article 3(22) of Directive 2009/31/EC;
‘fuel stream’ means a fuel as defined in Article 3, point (af), of Directive 2003/87/EC, released for consumption through specific physical means, such as pipelines, trucks, rail, ships or fuel stations, and giving rise to emissions of relevant greenhouse gases as a result of its consumption by categories of consumers in sectors covered by Annex III to Directive 2003/87/EC;
‘national fuel stream’ means the aggregation, per fuel type, of fuels streams of all regulated entities in the territory of a Member State;
‘scope factor’ means the factor between zero and one that is used to determine the share of a fuel stream that is used for combustion in sectors covered by Annex III to Directive 2003/87/EC;
‘released fuel amount’ means data on the amount of fuel as defined in Article 3, point (af), of Directive 2003/87/EC which is released for consumption and expressed as energy in terajoules, mass in tonnes or volume in normal cubic metres or the equivalent in litres, where appropriate, before application of a scope factor;
‘unit conversion factor’ means a factor converting the unit in which released fuel amounts are expressed, into amounts expressed as energy in terajoules, mass in tonnes or volume in normal cubic metres or the equivalent in litres, where appropriate, which comprises all relevant factors such as the density, the net calorific value or (for gases) the conversion from gross calorific value to net calorific value, as applicable;
‘final consumer’ for the purposes of this Regulation means any natural or legal person that is the end user of the fuel as defined in Article 3, point (af) of Directive 2003/87/EC, whose annual fuel consumption does not exceed 1 tonne of CO2;
‘released for consumption’ for the purposes of this Regulation means the moment where the excise duty on a fuel, as defined in Article 3, point (af), of Directive 2003/87/EC, becomes chargeable in accordance with Articles 6(2) and (3) of Council Directive (EU) 2020/262 ( 3 ) or, where applicable, in accordance with Article 21(5) of Council Directive 2003/96/EC ( 4 ), unless the Member State has used the flexibility provided under Article 3 (ae), point (iv), of Directive 2003/87/EC, in which case it means the moment designated by the Member State as creating obligations under Chapter IVa of that Directive.
SECTION 2
General principles
Article 4
General obligation
Operators and aircraft operators shall carry out their obligations related to the monitoring and reporting of greenhouse gas emissions under Directive 2003/87/EC in accordance with the principles laid down in Articles 5 to 9.
Article 5
Completeness
Monitoring and reporting shall be complete and 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 other relevant activities included pursuant to Article 24 of that Directive, and of all greenhouse gases specified in relation to those activities, while avoiding double-counting.
Operators and aircraft operators shall take appropriate measures to prevent any data gaps within the reporting period.
Article 6
Consistency, comparability and transparency
Article 7
Accuracy
Operators and aircraft operators shall ensure that emission determination is neither systematically nor knowingly inaccurate.
They shall identify and reduce any source of inaccuracies as far as possible.
They shall exercise due diligence to ensure that the calculation and measurement of emissions exhibit the highest achievable accuracy.
Article 8
Integrity of the methodology and of the emissions report
Operators and aircraft operators shall enable reasonable assurance of the integrity of emission data to be reported. They shall determine emissions using the appropriate monitoring methodologies set out in this Regulation.
Reported emission data and related disclosures shall be free from material misstatement as defined in Article 3(6) of Commission Implementing Regulation (EU) 2018/2067 ( 5 ), avoid bias in the selection and presentation of information, and provide a credible and balanced account of an installation's or aircraft operator's emissions.
In selecting a monitoring methodology, the improvements from greater accuracy shall be balanced against additional costs. Monitoring and reporting of emissions shall aim for the highest achievable accuracy, unless this is technically not feasible or incurs unreasonable costs.
Article 9
Continuous improvement
Operators and aircraft operators shall take account of the recommendations included in the verification reports issued pursuant to Article 15 of Directive 2003/87/EC in their consequent monitoring and reporting.
Article 10
Coordination
Where a Member State designates more than one competent authority pursuant to Article 18 of Directive 2003/87/EC, it shall coordinate the work carried out by those authorities pursuant to this Regulation.
CHAPTER II
MONITORING PLAN
SECTION 1
General rules
Article 11
General obligation
The monitoring plan shall be supplemented by written procedures which the operator or aircraft operator establishes, documents, implements and maintains for activities under the monitoring plan, as appropriate.
Article 12
Content and submission of the monitoring plan
The monitoring plan shall consist of a detailed, complete and transparent documentation of the monitoring methodology of a specific installation or aircraft operator and shall contain at least the elements laid down in Annex I.
Together with the monitoring plan, the operator or aircraft operator shall submit the following supporting documents:
for installations, evidence for each major and minor source stream demonstrating compliance with the uncertainty thresholds for activity data and calculation factors, where applicable, for the applied tiers as defined in Annexes II and IV, and for each emission source demonstrating compliance with the uncertainty thresholds for the applied tiers as defined in Annex VIII, where applicable;
the results of a risk assessment providing evidence that the proposed control activities and procedures for control activities are commensurate with the inherent risks and control risks identified.
The operator or aircraft operator shall summarise the procedures in the monitoring plan providing the following information:
the title of the procedure;
a traceable and verifiable reference for identification of the procedure;
identification of the post or department responsible for implementing the procedure and for the data generated from or managed by the procedure;
a brief description of the procedure, allowing the operator or aircraft operator, the competent authority and the verifier to understand the essential parameters and operations performed;
the location of relevant records and information;
the name of the computerised system used, where applicable;
a list of EN standards or other standards applied, where relevant.
The operator or aircraft operator shall make any written documentation of the procedures available to the competent authority upon request. The operator or aircraft operator shall also make them available for the purposes of verification pursuant to Implementing Regulation (EU) 2018/2067.
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Article 13
Standardised and simplified monitoring plans
For that purpose, Member States may publish templates for those monitoring plans, including the description of data flow and control procedures referred to in Articles 58 and 59, based on the templates and guidelines published by the Commission.
Member States may require the operator or aircraft operator to carry out the risk assessment pursuant to the previous subparagraph itself, where appropriate.
Article 14
Modifications of the monitoring plan
The operator or aircraft operator shall modify the monitoring plan, at least, in any of the following situations:
new emissions occur due to new activities being carried out or due to the use of new fuels or materials not yet contained in the monitoring plan;
a change in the availability of data, due to the use of new types of measuring instrument, sampling methods or analysis methods, or for other reasons, leads to higher accuracy in the determination of emissions;
data resulting from the monitoring methodology applied previously has been found to be incorrect;
changing the monitoring plan improves the accuracy of the reported data, unless this is technically not feasible or incurs unreasonable costs;
the monitoring plan is not in conformity with the requirements of this Regulation and the competent authority requests the operator or aircraft operator to modify it;
it is necessary to respond to the suggestions for improvement of the monitoring plan contained in a verification report.
Article 15
Approval of modifications of the monitoring plan
However, the competent authority may allow the operator or aircraft operator to notify modifications of the monitoring plan that are not significant within the meaning of paragraphs 3 and 4 by 31 December of the same year.
Where the competent authority considers a modification not to be significant, it shall inform the operator or aircraft operator thereof without undue delay.
Significant modifications to the monitoring plan of an installation include:
changes to the category of the installation where such changes require a change to the monitoring methodology or lead to a change of the applicable materiality level pursuant to Article 23 of Implementing Regulation (EU) 2018/2067;
notwithstanding Article 47(8), changes regarding whether the installation is considered an ‘installation with low emissions’;
changes to emission sources;
a change from calculation-based to measurement-based methodologies, or vice versa, or from a fall-back methodology to a tier-based methodology for determining emissions or vice versa;
a change in the tier applied;
the introduction of new source streams;
a change in the categorisation of source streams – between major, minor or de-minimis source streams where such a change requires a change to the monitoring methodology;
a change to the default value for a calculation factor, where the value is to be laid down in the monitoring plan;
the introduction of new methods or changes to existing methods related to sampling, analysis or calibration, where this has a direct impact on the accuracy of emissions data;
the implementation or adaption of a quantification methodology for emissions from leakage at storage sites.
Significant changes to the monitoring plans of an aircraft operator include:
with regard to the emission monitoring plan:
a change of emission factor values laid down in the monitoring plan;
a change between calculation methods as laid down in Annex III, or a change from the use of a calculation method to the use of estimation methodology in accordance with Article 55(2) or vice versa;
the introduction of new source streams;
changes in the status of the aircraft operator as a small emitter within the meaning of Article 55(1) or with regard to one of the thresholds provided by Article 28a(6) of Directive 2003/87/EC;
▼M4 —————
Article 16
Implementation and record-keeping of modifications
In case of doubt, the operator or aircraft operator shall use in parallel both the modified and the original monitoring plan to carry out all monitoring and reporting in accordance with both plans, and it shall keep records of both monitoring results.
The operator or aircraft operator shall keep records of all modifications of the monitoring plan. Each record shall contain:
a transparent description of the modification;
a justification for the modification;
the date of notification of the modification to the competent authority pursuant to Article 15(1);
the date on which the competent authority acknowledged receipt of the notification referred to in Article 15(1), where available, and the date of the approval or information referred to in Article 15(2);
the starting date of implementation of the modified monitoring plan in accordance with paragraph 2 of this Article.
SECTION 2
Technical feasibility and unreasonable costs
Article 17
Technical feasibility
Where an operator or aircraft operator claims that applying a specific monitoring methodology is technically not feasible, the competent authority shall assess the technical feasibility taking the operator's or aircraft operator's justification into account. That justification shall be based on the operator or aircraft operator having technical resources capable of meeting the needs of a proposed system or requirement that can be implemented in the required time for the purposes of this Regulation. Those technical resources shall include the availability of the requisite techniques and technology.
Article 18
Unreasonable costs
The competent authority shall consider costs unreasonable where the cost estimate exceeds the benefit. To that end, the benefit shall be calculated by multiplying an improvement factor by a reference price of EUR 80 per allowance and costs shall include an appropriate depreciation period based on the economic lifetime of the equipment.
In the absence of such data on the average annual emissions caused by that source stream over the three most recent years, the operator or aircraft operator shall provide a conservative estimate of the annual average emissions, with the exclusion of CO2 stemming from biomass and before subtraction of transferred CO2. For measuring instruments under national legal metrological control, the uncertainty currently achieved may be substituted by the maximum permissible error in service allowed by the relevant national legislation.
For the purpose of this paragraph, Article 38(5) shall apply, provided that the relevant information on the sustainability and the greenhouse gas emissions saving criteria of biofuels, bioliquids and biomass fuels used for combustion is available to the operator.
When assessing the unreasonable nature of the costs with regard to measures increasing the quality of reported emissions but without direct impact on the accuracy of activity data, the competent authority shall use an improvement factor of 1 % of the average annual emissions of the respective source streams in the three most recent reporting periods. Those measures may include:
switching from default values to analyses to determine calculation factors;
an increase of the number of analyses per source stream;
where the specific measuring task does not fall under national legal metrological control, the substitution of measuring instruments with instruments complying with relevant requirements of legal metrological control of the Member State in similar applications, or to measuring instruments meeting national rules adopted pursuant to Directive 2014/31/EU of the European Parliament and of the Council ( 6 ) or Directive 2014/32/EU;
shortening calibration and maintenance intervals of measuring instruments;
improvements to data-flow activities and control activities that significantly reduce the inherent or control risk.
CHAPTER III
MONITORING OF EMISSIONS FROM STATIONARY INSTALLATIONS
SECTION 1
General provisions
Article 19
Categorisation of installations, source streams and emission sources
The operator shall classify each installation in one of the following categories:
a category A installation, where the average verified annual emissions in the trading period immediately preceding the current trading period, with the exclusion of CO2 stemming from biomass and before subtraction of transferred CO2, are equal to or less than 50 000 tonnes of CO2(e);
a category B installation, where the average verified annual emissions of the trading period immediately preceding the current trading period, with the exclusion of CO2 stemming from biomass and before subtraction of transferred CO2, are more than 50 000 tonnes of CO2(e) and equal to or less than 500 000 tonnes of CO2(e);
a category C installation, where the average verified annual emissions of the trading period immediately preceding the current trading period, with the exclusion of CO2 stemming from biomass and before subtraction of transferred CO2, are more than 500 000 tonnes of CO2(e).
By way of derogation from Article 14(2), the competent authority may allow the operator not to modify the monitoring plan where, on the basis of verified emissions, the threshold for the classification of the installation referred to in the first subparagraph is exceeded, but the operator demonstrates to the satisfaction of the competent authority that this threshold has not already been exceeded within the past five reporting periods and will not be exceeded again in subsequent reporting periods.
The operator shall classify each source stream in one of the following categories, comparing it against the sum of all absolute values of fossil CO2 and CO2(e) corresponding to all source streams included in calculation-based methodologies and of all emissions of emission sources monitored using measurement-based methodologies, before subtraction of transferred CO2:
minor source streams, where the source streams selected by the operator jointly account for less than 5 000 tonnes of fossil CO2 per year or less than 10 %, up to a total maximum of 100 000 tonnes of fossil CO2 per year, whichever is greater in terms of absolute value;
de minimis source streams, where the source streams selected by the operator jointly account for less than 1 000 tonnes of fossil CO2 per year or less than 2 %, up to a total maximum of 20 000 tonnes of fossil CO2 per year, whichever is greater in terms of absolute value;
major source streams, where the source streams do not fall within the categories referred to in points (a) and (b).
By way of derogation from Article 14(2), the competent authority may allow the operator not to modify the monitoring plan where, on the basis of verified emissions, the threshold for the classification of a source stream as a minor source stream or a de minimis source stream referred to in the first subparagraph is exceeded, but the operator demonstrates to the satisfaction of the competent authority that this threshold has not already been exceeded within the past five reporting periods and will not be exceeded again in subsequent reporting periods.
The operator shall classify each emission source for which a measurement-based methodology is applied in one of the following categories:
minor emission sources, where the emission source emits less than 5 000 tonnes of fossil CO2(e) per year or less than 10 % of the installation's total fossil emissions, up to a maximum of 100 000 tonnes of fossil CO2(e) per year, whichever is greater in terms of absolute value;
major emission sources, where the emission source does not classify as a minor emission source.
By way of derogation from Article 14(2), the competent authority may allow the operator not to modify the monitoring plan where, on the basis of verified emissions, the threshold for the classification of an emission source as a minor emission source referred to in the first subparagraph is exceeded, but the operator demonstrates to the satisfaction of the competent authority that this threshold has not already been exceeded within the past five reporting periods and will not be exceeded again in subsequent reporting periods.
Article 20
Monitoring boundaries
Within those boundaries, the operator shall include all relevant greenhouse gas emissions from all emission sources and source streams belonging to activities carried out at the installation and listed in Annex I to Directive 2003/87/EC, and from activities and greenhouse gases included by the Member State in which the installation is situated, pursuant to Article 24 of that Directive.
The operator shall also include emissions from regular operations and abnormal events, including start-up, shut-down and emergency situations, over the reporting period, with the exception of emissions from mobile machinery for transportation purposes.
The competent authority may allow the exclusion of a leakage emission source from the monitoring and reporting process, once corrective measures pursuant to Article 16 of Directive 2009/31/EC have been taken and emissions or release into the water column from that leakage can no longer be detected.
Article 21
Choice of the monitoring methodology
A calculation-based methodology shall consist in determining emissions from source streams on the basis of activity data obtained by means of measurement systems and additional parameters from laboratory analyses or default values. The calculation-based methodology may be implemented according to the standard methodology set out in Article 24 or the mass-balance methodology set out in Article 25.
A measurement-based methodology shall consist in determining emissions from emission sources by means of continuous measurement of the concentration of the relevant greenhouse gas in the flue gas and of the flue-gas flow, including the monitoring of CO2 transfers between installations where the CO2 concentration and the flow of the transferred gas are measured.
Where the calculation-based methodology is applied, the operator shall determine for each source stream, in the monitoring plan, whether the standard methodology or the mass-balance methodology is used, including the relevant tiers in accordance with Annex II.
Article 22
Monitoring methodology not based on tiers
By way of derogation from Article 21(1), the operator may use a monitoring methodology that is not based on tiers (hereinafter ‘the fall-back methodology’) for selected source streams or emission sources, provided that all of the following conditions are met:
applying at least tier 1 under the calculation-based methodology for one or more major source streams or minor source streams and a measurement-based methodology for at least one emission source related to the same source streams is technically not feasible or would incur unreasonable costs;
the operator assesses and quantifies each year the uncertainties of all parameters used for the determination of the annual emissions in accordance with the ISO guide to the expression of uncertainty in measurement (JCGM 100:2008) or another equivalent internationally accepted standard, and includes the results in the annual emissions report;
the operator demonstrates to the satisfaction of the competent authority that by applying such a fall-back monitoring methodology, the overall uncertainty thresholds for the annual level of greenhouse gas emissions for the whole installation do not exceed 7,5 % for category A installations, 5,0 % for category B installations and 2,5 % for category C installations.
Article 23
Temporary changes to the monitoring methodology
The operator shall take all necessary measures to allow the prompt resumption of the application of the monitoring plan as approved by the competent authority.
The operator concerned shall notify the competent authority of the temporary change referred to in paragraph 1 to the monitoring methodology without undue delay to the competent authority, specifying:
the reasons for deviating from the monitoring plan as approved by the competent authority;
the details of the interim monitoring methodology that the operator is using to determine the emissions until the conditions for the application of the monitoring plan as approved by the competent authority have been restored;
the measures the operator is taking to restore the conditions for the application of the monitoring plan as approved by the competent authority;
the anticipated point in time when application of the monitoring plan as approved by the competent authority will be resumed.
SECTION 2
Calculation-based methodology
Article 24
Calculation of emissions under the standard methodology
The competent authority may allow the use of emission factors for fuels expressed as t CO2/t or t CO2/Nm3. In such cases, the operator shall determine combustion emissions by multiplying the activity data related to the amount of fuel combusted, expressed as tonnes or normal cubic metres, by the corresponding emission factor and the corresponding oxidation factor.
Article 25
Calculation of emissions under the mass balance methodology
Article 26
Applicable tiers
When defining the relevant tiers for major and minor source streams in accordance with Article 21(1), to determine the activity data and each calculation factor, each operator shall apply the following:
at least the tiers listed in Annex V, in the case of a category A installation, or where a calculation factor is required for a source stream that is a commercial standard fuel;
in other cases than those referred to in point (a), the highest tier as defined in Annex II.
However, for major source streams the operator may apply a tier one level lower than required in accordance with the first subparagraph for category C installations and up to two levels lower for category A and B installations, with a minimum of tier 1, where it shows to the satisfaction of the competent authority that the tier required in accordance with the first subparagraph is technically not feasible or incurs unreasonable costs.
The competent authority may, for a transitional period agreed with the operator, allow an operator to apply tiers for major source streams that are lower than those referred to in the second subparagraph, with a minimum of tier 1, provided that:
the operator shows to the satisfaction of the competent authority that the tier required pursuant to the second subparagraph is technically not feasible or incurs unreasonable costs; and
the operator provides an improvement plan indicating how and by when at least the tier required pursuant to the second subparagraph will be reached.
Article 27
Determination of activity data
The operator shall determine the activity data of a source stream in one of the following ways:
on the basis of continual metering at the process which causes the emissions;
on the basis of aggregation of metering of quantities delivered separately, taking into account relevant stock changes.
Where it is technically not feasible or would incur unreasonable costs to determine quantities in stock by direct measurement, the operator may estimate those quantities on the basis of one of the following:
data from previous years correlated with output for the reporting period;
documented procedures and respective data in audited financial statements for the reporting period.
Where it is technically not feasible or would incur unreasonable costs to determine activity data for the entire calendar year, the operator may choose the next most appropriate day to separate one reporting year from the subsequent year, and reconcile accordingly to the calendar year required. The deviations involved for one or more source streams shall be clearly recorded, form the basis of a value representative for the calendar year, and be considered consistently in relation to the next year.
Article 28
Measurement systems under the operator's control
To determine activity data in accordance with Article 27, the operator shall use metering results based on measurement systems under its own control at the installation, provided that all of the following conditions are complied with:
the operator must carry out an uncertainty assessment and ensures that the uncertainty threshold of the relevant tier level is met;
the operator must ensure at least once a year and after each calibration of a measuring instrument that the calibration results multiplied by a conservative adjustment factor are compared with the relevant uncertainty thresholds. The conservative adjustment factor shall be based on an appropriate time series of previous calibrations of that or similar measuring instruments for taking into account the effect of uncertainty in service.
Where tier thresholds approved in accordance with Article 12 are exceeded or equipment found not to conform with other requirements, the operator shall take corrective action without undue delay and notify the competent authority thereof.
The assessment shall cover the specified uncertainty of the applied measuring instruments, uncertainty associated with the calibration, and any additional uncertainty connected to how the measuring instruments are used in practice. The uncertainty assessment shall cover uncertainty related to stock changes where the storage facilities are capable of containing at least 5 % of the annual used quantity of the fuel or material considered. When carrying out the assessment, the operator shall take into account the fact that the stated values used to define tier uncertainty thresholds in Annex II refer to the uncertainty over the full reporting period.
The operator may simplify the uncertainty assessment by assuming that the maximum permissible errors specified for the measuring instrument in service or, where lower, the uncertainty obtained by calibration, multiplied by a conservative adjustment factor for taking into account the effect of uncertainty in service, are to be regarded as the uncertainty over the whole reporting period as required by the tier definitions in Annex II, provided that measuring instruments are installed in an environment appropriate for their use specifications.
For that purpose, the maximum permissible error in service allowed by the relevant national legislation on legal metrological control for the relevant measuring task may be used as the uncertainty value without providing further evidence.
Article 29
Measurement systems outside the operator's own control
To that end, the operator may revert to one of the following data sources:
amounts from invoices issued by a trade partner, provided that a commercial transaction between two independent trade partners takes place;
direct readings from the measurement systems.
To that end, the maximum permissible error in service allowed by relevant legislation for national legal metrological control for the relevant commercial transaction may be used as uncertainty without providing further evidence.
Where the applicable requirements under national legal metrological control are less stringent than the applicable tier pursuant to Article 26, the operator shall obtain evidence on the applicable uncertainty from the trade partner responsible for the measurement system.
Article 30
Determination of calculation factors
Where such an approach incurs unreasonable costs or where higher accuracy can be achieved, the operator may consistently report activity data and calculation factors referring to the state in which laboratory analyses are carried out.
The operator shall be required to determine the biomass fraction only for mixed fuels or materials. For other fuels or materials the default value of 0 % for the biomass fraction of fossil fuels or materials shall be used, and a default value of 100 % biomass fraction for biomass fuels or materials consisting exclusively of biomass.
Article 31
Default values for calculation factors
Where the operator determines calculation factors as default values, it shall use one of the following values, in accordance with the requirement of the applicable tier as set out in Annexes II and VI:
standard factors and stoichiometric factors listed in Annex VI;
standard factors used by the Member State for its national inventory submission to the Secretariat of the United Nations Framework Convention on Climate Change;
literature values agreed with the competent authority, including standard factors published by the competent authority, which are compatible with factors referred to in point (b), but representative of more disaggregated sources of fuel streams;
values specified and guaranteed by the supplier of a fuel or material where the operator can demonstrate to the satisfaction of the competent authority that the carbon content exhibits a 95 % confidence interval of not more than 1 %;
values based on analyses carried out in the past, where the operator can demonstrate to the satisfaction of the competent authority that those values are representative for future batches of the same fuel or material.
Where the default values change on an annual basis, the operator shall specify the authoritative applicable source of that value in the monitoring plan.
Article 32
Calculation factors based on analyses
Where such standards are not available, the methods shall be based on suitable ISO standards or national standards. Where no applicable published standards exist, suitable draft standards, industry best-practice guidelines or other scientifically proven methodologies shall be used, limiting sampling and measurement bias.
When determining a specific parameter, the operator shall use the results of all analyses made with regard to that parameter.
Article 33
Sampling plan
The operator shall ensure that the derived samples are representative for the relevant batch or delivery period and free of bias. Relevant elements of the sampling plan shall be agreed with the laboratory carrying out the analysis for the respective fuel or material, and evidence of that agreement shall be included in the plan. The operator shall make the plan available for the purposes of verification pursuant to Implementing Regulation (EU) 2018/2067.
Article 34
Use of laboratories
With respect to quality management, the operator shall produce an accredited certification of the laboratory in conformity with EN ISO/IEC 9001, or other certified quality management systems that cover the laboratory. In the absence of such certified quality management systems, the operator shall provide other appropriate evidence that the laboratory is capable of managing its personnel, procedures, documents and tasks in a reliable manner.
With respect to technical competence, the operator shall provide evidence that the laboratory is competent and able to generate technically valid results using the relevant analytical procedures. Such evidence shall cover at least the following elements:
management of the personnel's competence for the specific tasks assigned;
suitability of accommodation and environmental conditions;
selection of analytical methods and relevant standards;
where applicable, management of sampling and sample preparation, including control of sample integrity;
where applicable, development and validation of new analytical methods or application of methods not covered by international or national standards;
uncertainty estimation;
management of equipment, including procedures for calibration, adjustment, maintenance and repair of equipment, and record keeping thereof;
management and control of data, documents and software;
management of calibration items and reference materials;
quality assurance for calibration and test results, including regular participation in proficiency testing schemes, applying analytical methods to certified reference materials, or inter-comparison with an accredited laboratory;
management of outsourced processes;
management of assignments, customer complaints, and ensuring timely corrective action.
Article 35
Frequencies for analyses
The competent authority may allow the operator to use a frequency that differs from those referred to in paragraph 1, where minimum frequencies are not available or where the operator demonstrates one of the following:
based on historical data, including analytical values for the respective fuels or materials in the reporting period immediately preceding the current reporting period, any variation in the analytical values for the respective fuel or material does not exceed 1/3 of the uncertainty value to which the operator has to adhere with regard to the activity data determination of the relevant fuel or material;
using the required frequency would incur unreasonable costs.
Where an installation operates for part of the year only, or where fuels or materials are delivered in batches that are consumed over more than one calendar year, the competent authority may agree with the operator a more appropriate schedule for analyses, provided that it results in a comparable uncertainty as under point (a) of the first subparagraph.
Article 36
Emission factors for CO2
The competent authority may allow the operator to use an emission factor for a fuel expressed as t CO2/t or t CO2/Nm3 for combustion emissions, where the use of an emission factor expressed as t CO2/TJ incurs unreasonable costs or where at least equivalent accuracy of the calculated emissions can be achieved by using such an emission factor.
Article 37
Oxidation and conversion factors
However, the competent authority may require operators to always use tier 1.
Where several fuels are used within an installation and tier 3 is to be used for the specific oxidation factor, the operator may ask for the approval of the competent authority for one or both of the following:
the determination of one aggregate oxidation factor for the whole combustion process and to apply it to all fuels;
the attribution of the incomplete oxidation to one major source stream and use of a value of 1 for the oxidation factor of the other source streams.
Where biomass or mixed fuels are used, the operator shall provide evidence that application of points (a) or (b) of the first subparagraph does not lead to an under-estimation of emissions.
Article 38
Biomass source streams
For the purpose of this paragraph, Article 38(5) shall apply.
The emission factor of each fuel or material shall be calculated and reported as the preliminary emission factor, determined in accordance with Article 30, multiplied by the fossil fraction of the fuel or material.
For the purpose of this paragraph, Article 38(5) shall apply.
However, biofuels, bioliquids and biomass fuels produced from waste and residues, other than agricultural, aquaculture, fisheries and forestry residues are required to fulfil only the criteria laid down in Article 29(10) of Directive (EU) 2018/2001. This subparagraph shall also apply to waste and residues that are first processed into a product before being further processed into biofuels, bioliquids and biomass fuels.
Electricity, heating and cooling produced from municipal solid waste shall not be subject to the criteria laid down in Article 29(10) of Directive (EU) 2018/2001.
The criteria laid down in paragraphs 2 to 7 and 10 of Article 29 of Directive (EU) 2018/2001 shall apply irrespective of the geographical origin of the biomass.
Article 29(10) of Directive (EU) 2018/2001 shall apply to an installation as defined in Article 3(e) of Directive 2003/87/EC.
The compliance with the criteria laid down in paragraphs 2 to 7 and 10 of Article 29 of Directive (EU) 2018/2001 shall be assessed in accordance with Articles 30 and 31(1) of that Directive.
Where the biomass used for combustion does not comply with this paragraph, its carbon content shall be considered as fossil carbon.
Article 39
Determination of biomass and fossil fraction
Where, subject to the tier level required, the operator has to carry out analyses to determine the biomass fraction, but the application of the first subparagraph is technically not feasible or would incur unreasonable costs, the operator shall submit an alternative estimation method to determine the biomass fraction to the competent authority for approval. For fuels or materials originating from a production process with defined and traceable input streams, the operator may base the estimation on a mass balance of fossil and biomass carbon entering and leaving the process.
The Commission may provide guidelines on further applicable estimation methods.
For the purpose of this paragraph, paragraphs 3 and 4 of this Article shall apply regarding the biogas fraction of natural gas used as input.
The operator may determine that a certain quantity of natural gas from the gas grid is biogas by using the methodology set out in paragraph 4.
The operator may determine the biomass fraction using purchase records of biogas of equivalent energy content, provided that the operator provides evidence to the satisfaction of the competent authority that:
there is no double counting of the same biogas quantity, in particular that the biogas purchased is not claimed to be used by anyone else, including through a disclosure of a guarantee of origin as defined in Article 2(12) of Directive (EU) 2018/2001;
the operator and the producer of the biogas are connected to the same gas grid.
For the purpose of demonstrating compliance with this paragraph, the operator may use the data recorded in a database set up by one or more Member States which enables tracing of transfers of biogas.
SECTION 3
Measurement-based methodology
Article 40
Use of the measurement-based monitoring methodology
The operator shall use measurement-based methodologies for all emissions of nitrous oxide (N2O) as laid down in Annex IV, and to quantify CO2 transferred pursuant to Article 49.
In addition, the operator may use measurement-based methodologies for CO2 emission sources where it can provide evidence that for each emission source the tiers required in accordance with Article 41 are complied with.
Article 41
Tier requirements
For each major emission source, the operator shall apply the following:
in the case of a category A installation, at least the tiers listed in section 2 of Annex VIII;
in other cases, the highest tier listed in section 1 of Annex VIII.
However, the operator may apply a tier one level lower than required in accordance with the first subparagraph for category C installations and up to two levels lower for category A and B installations, with a minimum of tier 1, where it shows to the satisfaction of the competent authority that the tier required in accordance with the first subparagraph is technically not feasible or incurs unreasonable costs.
Article 42
Measurement standards and laboratories
All measurements shall be carried out applying methods based on:
EN 14181 (Stationary source emissions — Quality assurance of automated measuring systems);
EN 15259 (Air quality — Measurement of stationary source emissions — Requirements for measurement sections and sites and for the measurement objective, plan and report);
other relevant EN standards, in particular EN ISO 16911-2 (Stationary source emissions — Manual and automatic determination of velocity and volume flow rate in ducts).
Where such standards are not available, the methods shall be based on suitable ISO standards, standards published by the Commission or national standards. Where no applicable published standards exist, suitable draft standards, industry best practice guidelines or other scientifically proven methodologies shall be used, limiting sampling and measurement bias.
The operator shall consider all relevant aspects of the continuous measurement system, including the location of the equipment, calibration, measurement, quality assurance and quality control.
Where the laboratory does not have such accreditation, the operator shall ensure that equivalent requirements of Article 34(2) and (3) are met.
Article 43
Determination of emissions
In the case of CO2 emissions, the operator shall determine annual emissions on the basis of equation 1 in Annex VIII. CO emitted to the atmosphere shall be treated as the molar equivalent amount of CO2.
In the case of nitrous oxide (N2O), the operator shall determine annual emissions on the basis of the equation in subsection B.1 of section 16 of Annex IV.
The operator shall determine the greenhouse gas concentration in the flue gas by continuous measurement at a representative point through one of the following:
direct measurement;
in the case of high concentration in the flue gas, calculation of the concentration using an indirect concentration measurement applying equation 3 in Annex VIII and taking into account the measured concentration values of all other components of the gas stream as laid down in the operator's monitoring plan.
Where relevant, the operator shall determine separately any CO2 amount stemming from biomass and subtract it from the total measured CO2 emissions. For this purpose the operator may use:
a calculation based approach, including approaches using analyses and sampling based on EN ISO 13833 (Stationary source emissions — Determination of the ratio of biomass (biogenic) and fossil-derived carbon dioxide — Radiocarbon sampling and determination);
another method based on a relevant standard, including ISO 18466 (Stationary source emissions — Determination of the biogenic fraction in CO2 in stack gas using the balance method);
an estimation method published by the Commission.
Where the method proposed by the operator involves continuous sampling from the flue gas stream, EN 15259 (Air quality — Measurement of stationary source emissions — Requirements for measurement sections and sites and for the measurement objective, plan and report) shall be applied.
For the purpose of this paragraph, Article 38(5) shall apply.
Where the method proposed by the operator involves continuous sampling from the flue gas stream and the installation consumes natural gas from the grid, the operator shall subtract the CO2 stemming from any biogas contained in the natural gas from the total measured CO2 emissions. The biomass fraction of the natural gas shall be determined in accordance with Articles 32 to 35.
The operator shall determine the flue gas flow for the calculation in accordance with paragraph 1 by one of the following methods:
calculation by means of a suitable mass balance, taking into account all significant parameters on the input side, including for CO2 emissions at least input material loads, input airflow and process efficiency, and on the output side, including at least the product output and the concentration of oxygen (O2), sulphur dioxide (SO2) and nitrogen oxides (NOx);
determination by continuous flow measurement at a representative point.
Article 44
Data aggregation
Where an operator can generate data for shorter reference periods without additional cost, the operator shall use those periods for the determination of the annual emissions in accordance with Article 43(1).
Article 45(2) to (4) shall apply where fewer than 80 % of the maximum number of data points for a parameter are available.
Article 45
Missing data
Where the reporting period is not applicable for determining such substitution values due to significant technical changes at the installation, the operator shall agree with the competent authority a representative timeframe for determining the average and standard deviation, where possible with a duration of one year.
Article 46
Corroborating with calculation of emissions
The operator shall corroborate emissions determined by a measurement-based methodology, with the exception of N2O emissions from nitric acid production and greenhouse gases transferred to a transport network or a storage site, by calculating the annual emissions of each greenhouse gas in question for the same emission sources and source streams.
The use of tier methodologies shall not be required.
SECTION 4
Special provisions
Article 47
Installations with low emissions
The first subparagraph shall not apply to installations carrying out activities for which N2O is included pursuant to Annex I to Directive 2003/87/EC.
For the purposes of the first subparagraph of paragraph 1, an installation shall be considered an installation with low emissions where at least one of the following conditions is met:
the average annual emissions of that installation reported in the verified emissions reports during the trading period immediately preceding the current trading period, with the exclusion of CO2 stemming from biomass and before subtraction of transferred CO2, were less than 25 000 tonnes of CO2(e) per year;
the average annual emissions referred to in point (a) are not available or are no longer applicable because of changes to the installation's boundaries or changes to the operating conditions of the installation, but the annual emissions of that installation for the next five years, with the exclusion of CO2 stemming from biomass and before subtraction of transferred CO2, will be, based on a conservative estimation method, less than 25 000 tonnes of CO2(e) per year.
For the purpose of this paragraph, Article 38(5) shall apply.
The operator shall, without undue delay, submit a significant modification of the monitoring plan within the meaning of point (b) of Article 15(3), to the competent authority for approval.
However, the competent authority shall allow that the operator continues simplified monitoring provided that that operator demonstrates to the satisfaction of the competent authority that the threshold referred to in paragraph 2 has not already been exceeded within the past five reporting periods and will not be exceeded again from the following reporting period onwards.
Article 48
Inherent CO2
However, where inherent CO2 is emitted, or transferred out of the installation to entities not covered by that Directive, it shall be counted as emissions of the installation where it originates.
Where the quantities of transferred and received inherent CO2 are not identical, the arithmetical average of both determined values shall be used in both the transferring and receiving installations' emissions reports, where the deviation between the values can be explained by the uncertainty of the measurement systems or the determination method. In such cases, the emissions report shall refer to the alignment of that value.
Where the deviation between the values cannot be explained by the approved uncertainty range of the measurement systems or the determination method, the operators of the transferring and receiving installations shall align the values by applying conservative adjustments approved by the competent authority.
Article 49
Transferred CO2
The operator shall subtract from the emissions of the installation any amount of CO2 originating from fossil carbon in activities covered by Annex I to Directive 2003/87/EC that is not emitted from the installation, but:
transferred out of the installation to any of the following:
a capture installation for the purpose of transport and long-term geological storage in a storage site permitted under Directive 2009/31/EC;
a transport network with the purpose of long-term geological storage in a storage site permitted under Directive 2009/31/EC;
a storage site permitted under Directive 2009/31/EC for the purpose of long-term geological storage;
transferred out of the installation and used to produce precipitated calcium carbonate, in which the used CO2 is chemically bound.
The first subparagraph shall also apply to the receiving installation with respect to the transferring installation's installation identification code.
For the purpose of point (b) of paragraph 1, the operator shall apply a calculation-based methodology.
However, the operator may apply the next lower tier provided that it establishes that applying the highest tier as defined in section 1 of Annex VIII is technically not feasible or incurs unreasonable costs.
For determining the quantity of CO2 chemically bound in precipitated calcium carbonate, the operator shall use data sources representing highest achievable accuracy.
Article 50
Use or transfer of N2O
An installation that receives N2O from an installation and activity in accordance with the first subparagraph shall monitor the relevant gas streams using the same methodologies, as required by this Regulation, as if the N2O were generated within the receiving installation itself.
However, where N2O is bottled or used as a gas in products so that it is emitted outside the installation, or where it is transferred out of the installation to entities not covered by Directive 2003/87/EC, it shall be counted as emissions of the installation where it originates, except for quantities of N2O in respect of which the operator of the installation where the N2O originates can demonstrate to the competent authority that the N2O is destroyed using suitable emissions abatement equipment.
The first subparagraph shall also apply to the receiving installation with respect to the transferring installation's installation identification code.
However, the operator may apply the next lower tier provided that it establishes that applying the highest tier as defined in section 1 of Annex VIII is technically not feasible or incurs unreasonable costs.
CHAPTER IV
MONITORING OF EMISSIONS FROM AVIATION
Article 51
General provisions
To that end, the aircraft operator shall attribute all flights to the calendar year according to the time of departure measured in Coordinated Universal Time.
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For the purpose of identifying the unique aircraft operator referred to in point (o) of Article 3 of Directive 2003/87/EC that is responsible for a flight, the call sign used for air traffic control purposes, shall be used. The call sign shall be one of the following:
the ICAO designator laid down in box 7 of the flight plan;
where the ICAO designator of the aircraft operator is not available, the registration markings of the aircraft.
Article 52
Submission of monitoring plans
By way of derogation from the first subparagraph, an aircraft operator that performs an aviation activity covered by Annex I to Directive 2003/87/EC for the first time that could not be foreseen four months in advance of the activity shall submit a monitoring plan to the competent authority without undue delay, but no later than six weeks after performance of that activity. The aircraft operator shall provide adequate justification to the competent authority why a monitoring plan could not be submitted four months in advance of the activity.
Where the administering Member State referred to in Article 18a of Directive 2003/87/EC is not known in advance, the aircraft operator shall without undue delay submit the monitoring plan when information on the competent authority of the administering Member State becomes available.
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Article 53
Monitoring methodology for emissions from aviation activities
For the purpose of reporting pursuant to Article 7 of Commission Delegated Regulation (EU) 2019/1603 ( 7 ), the aircraft operator shall determine and report as a memo-item the CO2 emissions which result from multiplying the annual consumption of each fuel by the preliminary emission factor.
Each aircraft operator shall determine the fuel uplift referred to in section 1 of Annex III based on one of the following:
the measurement by the fuel supplier, as documented in the fuel delivery notes or invoices for each flight;
data from aircraft onboard measurement systems recorded in the mass and balance documentation, in the aircraft technical log or transmitted electronically from the aircraft to the aircraft operator.
The procedure for informing the use of actual or standard density shall be described in the monitoring plan along with a reference to the relevant aircraft operator documentation.
The aircraft operators shall use the default emissions factors set out in Table 1 in Annex III as the preliminary emission factor.
For fuels not listed in that table, the aircraft operator shall determine the emission factor in accordance with Article 32. For such fuels, the net calorific value shall be determined and reported as a memo-item.
Article 54
Specific provisions for biofuels
Additionally, the aircraft operator shall provide evidence to the satisfaction of the competent authority that the biofuel is attributed to the flight immediately following the fuel uplift of that flight.
Where several subsequent flights are carried out without fuel uplift between these flights, the aircraft operator shall split the amount of biofuel and assign it to these flights proportionally to the emissions from those flights calculated using the preliminary emission factor.
Where biofuel cannot be physically attributed at an aerodrome to a specific flight, the aircraft operator shall attribute the biofuels to its flights for which allowances have to be surrendered in accordance with Article 12(3) of Directive 2003/87/EC proportionally to the emissions from those flights departing from that aerodrome calculated using the preliminary emission factor.
The aircraft operator may determine the biomass fraction using purchase records of biofuel of equivalent energy content, provided that the aircraft operator provides evidence to the satisfaction of the competent authority that the biofuel was delivered to the fuelling system of the departure aerodrome in the reporting period, or 3 months before the start, or 3 months after the end, of that reporting period.
For the purpose of paragraphs 2 and 3 of this Article, the aircraft operator shall provide evidence to the satisfaction of the competent authority that:
the total amount of biofuel claimed does not exceed the total fuel usage of that aircraft operator for flights for which allowances have to be surrendered according to Article 12(3) of Directive 2003/87/EC, originating from the aerodrome at which the biofuel is supplied;
the amount of biofuel for flights for which allowances have to be surrendered according to Article 12(3) of Directive 2003/87/EC does not exceed the total quantity of biofuel purchased from which the total quantity of biofuel sold to third parties is subtracted;
the biomass fraction of the biofuel attributed to flights aggregated per aerodrome pair does not exceed the maximum blending limit for that biofuel as certified according to a recognised international standard;
there is no double counting of the same biofuel quantity, in particular that the biofuel purchased is not claimed to be used in an earlier report or by anyone else, or in another system.
For the purpose of points (a) to (c) of the first subparagraph, any fuel remaining in tanks after a flight and before an uplift is assumed to be 100 % fossil fuel.
For the purpose of demonstrating compliance with the requirements referred to under point (d) of the first subparagraph of this paragraph, the aircraft operator may use the data recorded in the Union database set up in accordance with Article 28(2) of Directive (EU) 2018/2001.
For the purpose of this paragraph, Article 38(5) shall apply to combustion of biofuel by aircraft operators.
The emission factor of each mixed fuel shall be calculated and reported as the preliminary emission factor multiplied by the fossil fraction of the fuel.
Article 54a
Specific provisions for eligible aviation fuels
Additionally, the aircraft operator shall provide evidence to the satisfaction of the competent authority that the eligible aviation fuel is attributed to the flight immediately following the uplift of that flight.
Where several subsequent flights are carried out without fuel uplift between these flights, the aircraft operator shall split the amount of eligible aviation fuel and assign it to these flights proportionally to the emissions from those flights calculated using the preliminary emission factor.
The aircraft operator may determine the eligible fraction using purchase records of the eligible aviation fuel of equivalent energy content, provided that the aircraft operator provides evidence to the satisfaction of the competent authority that the eligible aviation fuel was delivered to the fuelling system of the departure aerodrome in the reporting period or 3 months before the start, or 3 months after the end, of that reporting period.
For the purpose of paragraphs 4 and 5 of this Article, the aircraft operator shall provide evidence to the satisfaction of the competent authority that:
the total amount of eligible aviation fuel claimed does not exceed the total fuel usage of that aircraft operator for flights for which allowances have to be surrendered according to Article 12(3) of Directive 2003/87/EC, originating from the aerodrome at which the eligible aviation fuel is supplied;
the amount of eligible aviation fuel for flights for which allowances have to be surrendered according to Article 12(3) of Directive 2003/87/EC does not exceed the total quantity of eligible aviation fuel purchased from which the total quantity of eligible aviation fuel sold to third parties is subtracted;
the eligible fraction of the eligible aviation fuel attributed to flights aggregated per aerodrome pair does not exceed the maximum blending limit for that eligible aviation fuel as certified according to a recognised international standard, if such limitation applies;
there is no double counting of the same eligible aviation fuel quantity, in particular that the eligible aviation fuel purchased is not claimed to be used in an earlier report or by anyone else, or in another system.
For the purpose of points (a) to (c) of the first subparagraph, any fuel remaining in tanks after a flight and before an uplift is assumed to be 100 % fossil fuel.
For the purpose of demonstrating compliance with the requirements referred to under point (d) of the first subparagraph of this paragraph and where applicable, the aircraft operator may use the data recorded in the Union database set up in accordance with Article 28(2) of Directive (EU) 2018/2001.
Article 55
Small emitters
The applicable tools may only be used if they are approved by the Commission including the application of correction factors to compensate for any inaccuracies in the modelling methods.
By way of derogation from Article 12, a small emitter that intends to make use of any of the tools referred to in paragraph 2 of this Article may submit only the following information in the monitoring plan for emissions:
information required pursuant to point 1 of section 2 of Annex I;
evidence that the thresholds for small emitters set out in paragraph 1 of this Article are met;
the name of or reference to the tool as referred to in paragraph 2 of this Article that will be used for estimating the fuel consumption.
A small emitter shall be exempted from the requirement to submit the supporting documents referred to in the third subparagraph of Article 12(1).
The aircraft operator shall, without undue delay, submit a significant modification of the monitoring plan within the meaning of point (iv) of Article 15(4)(a) to the competent authority for approval.
However, the competent authority shall allow that the aircraft operator continues to use a tool referred to in paragraph 2 provided that that aircraft operator demonstrates to the satisfaction of the competent authority that the thresholds referred to in paragraph 1 have not already been exceeded within the past five reporting periods and will not be exceeded again from the following reporting period onwards.
Article 56
Sources of uncertainty
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CHAPTER V
DATA MANAGEMENT AND CONTROL
Article 58
Data flow activities
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Descriptions of written procedures for data flow activities in the monitoring plan shall at least cover the following elements:
the items of information listed in Article 12(2);
identification of the primary data sources;
each step in the data flow from primary data to annual emissions which shall reflect the sequence and interaction between the data flow activities, including relevant formulas and data aggregation steps applied;
the relevant processing steps related to each specific data flow activity, including the formulas and data used to determine the emissions;
relevant electronic data processing and storage systems used and the interaction between such systems and other inputs, including manual input;
the way outputs of data flow activities are recorded.
Article 59
Control system
The control system referred to in paragraph 1 shall consist of the following:
an operator's or aircraft operator's assessment of inherent risks and control risks based on a written procedure for carrying out the assessment;
written procedures related to control activities that are to mitigate the risks identified.
Written procedures related to control activities as referred to in point (b) of paragraph 2 shall at least include:
quality assurance of the measurement equipment;
quality assurance of the information technology system used for data flow activities, including process control computer technology;
segregation of duties in the data flow activities and control activities, and management of necessary competencies;
internal reviews and validation of data;
corrections and corrective action;
control of out-sourced processes;
keeping records and documentation including the management of document versions.
Whenever the control system is found to be ineffective or not commensurate with the risks identified, the operator or aircraft operator shall seek to improve the control system and update the monitoring plan or the underlying written procedures for data flow activities, risk assessments and control activities as appropriate.
Article 60
Quality assurance
Where components of the measuring systems cannot be calibrated, the operator shall identify those in the monitoring plan and propose alternative control activities.
When the equipment is found not to comply with required performance, the operator shall promptly take necessary corrective action.
Where such quality assurance requires emission limit values (ELVs) as necessary parameters for the basis of calibration and performance checks, the annual average hourly concentration of the greenhouse gas shall be used as a substitute for such ELVs. Where the operator finds a non-compliance with the quality assurance requirements, including that recalibration has to be performed, it shall report that circumstance to the competent authority and take corrective action without undue delay.
Article 61
Quality assurance of information technology
For the purposes of point (b) of Article 59(3), the operator or aircraft operator shall ensure that the information technology system is designed, documented, tested, implemented, controlled and maintained in a way to process reliable, accurate and timely data in accordance with the risks identified in accordance with point (a) of Article 59(2).
The control of the information technology system shall include access control, control of back up, recovery, continuity planning and security.
Article 62
Segregation of duties
For the purposes of point (c) of Article 59(3), the operator or aircraft operator shall assign responsible persons for all data flow activities and for all control activities in a way to segregate conflicting duties. In the absence of other control activities, it shall ensure for all data flow activities commensurate with the identified inherent risks that all relevant information and data shall be confirmed by at least one person who has not been involved in the determination and recording of that information or data.
The operator or aircraft operator shall manage the necessary competencies for the responsibilities involved, including the appropriate assignment of responsibilities, training, and performance reviews.
Article 63
Internal reviews and validation of data
Such review and validation of the data shall at least include:
a check as to whether the data are complete;
a comparison of the data that the operator or aircraft operator has obtained, monitored and reported over several years;
a comparison of data and values resulting from different operational data collection systems, including the following comparisons, where applicable:
a comparison of fuel or material purchasing data with data on stock changes and data on consumption for the applicable source streams;
a comparison of calculation factors that have been determined by analysis, calculated or obtained from the supplier of the fuel or material, with national or international reference factors of comparable fuels or materials;
a comparison of emissions obtained from measurement-based methodologies and the results of the corroborating calculation pursuant to Article 46;
a comparison of aggregated data and raw data.
Article 64
Corrections and corrective action
For the purpose of paragraph 1, the operator or aircraft operator shall at least proceed to all of the following:
assessment of the validity of the outputs of the applicable steps in the data flow activities referred to in Article 58 or control activities referred to in Article 59;
determination of the cause of the malfunctioning or error concerned;
Implementation of appropriate corrective action, including correcting any affected data in the emission report as appropriate.
Article 65
Out-sourced processes
Where the operator or aircraft operator outsources one or more data flow activities referred to in Article 58 or control activities referred to in Article 59, the operator or aircraft operator shall proceed to all of the following:
check the quality of the outsourced data flow activities and control activities in accordance with this Regulation;
define appropriate requirements for the outputs of the outsourced processes and the methods used in those processes;
check the quality of the outputs and methods referred to in point (b) of this Article;
ensure that outsourced activities are carried out such that those are responsive to the inherent risks and control risks identified in the risk assessment referred to in Article 59.
Article 66
Treatment of data gaps
Where the operator has not laid down the estimation method in a written procedure, it shall establish such a written procedure and submit to the competent authority for approval an appropriate modification of the monitoring plan in accordance with Article 15.
Where surrogate data cannot be determined in accordance with the first subparagraph of this paragraph, the emissions for that flight or those flights may be estimated by the aircraft operator from the fuel consumption determined by using a tool referred to in Article 55(2).
Where the number of flights with data gaps referred to in the first two sub-paragraphs exceed 5 % of the annual flights that are reported, the operator shall inform the competent authority thereof without undue delay and shall take remedial action for improving the monitoring methodology.
Article 67
Records and documentation
The documented and archived monitoring data shall allow for the verification of the annual emissions reports in accordance with Implementing Regulation (EU) 2018/2067. Data reported by the operator or aircraft operator contained in an electronic reporting and data management system set up by the competent authority may be considered to be retained by the operator or aircraft operator, if they can access those data.
The operator or aircraft operator shall, upon request, make those documents available to the competent authority and to the verifier verifying the emissions report in accordance with Implementing Regulation (EU) 2018/2067.
CHAPTER VI
REPORTING REQUIREMENTS
Article 68
Timing and obligations for reporting
However, competent authorities may require operators or aircraft operators to submit the verified annual emission report earlier than by 31 March, but by 28 February at the earliest.
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Where the Competent Authority has corrected the verified emissions after 30 April each year, Member States shall notify this correction to the Commission without undue delay.
Article 69
Reporting on improvements to the monitoring methodology
An operator of an installation shall submit to the competent authority for approval a report containing the information referred to in paragraph 2 or 3, where appropriate, by the following deadlines:
for a category A installation, by 30 June every 5 years;
for a category B installation, by 30 June every 3 years;
for a category C installation, by 30 June every 2 years.
However, the competent authority may set an alternative date for submission of the report, but no later date than 30 September of the same year.
By way of derogation from the second and third subparagraphs, and without prejudice to the first subparagraph, the competent authority may approve, together with the monitoring plan or the improvement report, an extension of the deadline applicable pursuant to the second subparagraph, if the operator provides evidence to the satisfaction of the competent authority upon submission of a monitoring plan in accordance with Article 12 or upon notification of updates in accordance with Article 15, or upon submission of an improvement report in accordance with this Article, that the reasons for unreasonable costs or for improvement measures being technically not feasible will remain valid for a longer period of time. That extension shall take into account the number of years for which the operator provides evidence. The total time period between improvement reports shall not exceed three years for a category C installation, four years for a category B installation or five years for a category A installation.
However, where evidence is found that measures needed for reaching those tiers have become technically feasible and do not any more incur unreasonable costs, the operator shall notify the competent authority of appropriate modifications of the monitoring plan in accordance with Article 15, and submit proposals for implementing the related measures and its timing.
However, where evidence is found that measures needed for reaching at least tier 1 for those source streams have become technically feasible and do not any more incur unreasonable costs, the operator shall notify the competent authority of appropriate modifications of the monitoring plan in accordance with Article 15 and submit proposals for implementing the related measures and its timing.
The competent authority may set an alternative date for submission of the report as referred to in this paragraph, but no later date than 30 September of the same year. Where applicable, such report may be combined with the report referred to in paragraph 1 of this Article.
Where recommended improvements would not lead to an improvement of the monitoring methodology, the operator or aircraft operator shall provide a justification of why that is the case. Where the recommended improvements would incur unreasonable costs, the operator or aircraft operator shall provide evidence of the unreasonable nature of the costs.
Article 70
Determination of emissions by the competent authority
The competent authority shall make a conservative estimate of the emissions of an installation or aircraft operator in any of the following situations:
no verified annual emission report has been submitted by the operator or aircraft operator by the deadline required pursuant to Article 68(1);
the verified annual emissions report referred to in Article 68(1) is not in compliance with this Regulation;
the annual emissions report of an operator or aircraft operator has not been verified in accordance with Implementing Regulation (EU) 2018/2067.
Article 71
Access to information
Emission reports held by the competent authority shall be made available to the public by that authority subject to national rules adopted pursuant to Directive 2003/4/EC of the European Parliament and of the Council ( 8 ). With regard to the application of the exception, as specified in Article 4(2)(d) of Directive 2003/4/EC, operators or aircraft operators may indicate in their reports what information they consider commercially sensitive.
Article 72
Rounding of data
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Article 73
Ensuring consistency with other reporting
Each activity listed in Annex I to Directive 2003/87/EC that is carried out by an operator or aircraft operator shall be labelled using the codes, where applicable, from the following reporting schemes:
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;
the installation's identification number in the European pollutant release and transfer register in accordance with Regulation (EC) No 166/2006 of the European Parliament and of the Council ( 9 );
the activity of Annex I to Regulation (EC) No 166/2006;
the NACE code in accordance with Regulation (EC) No 1893/2006 of the European Parliament and of the Council ( 10 ).
CHAPTER VII
INFORMATION TECHNOLOGY REQUIREMENTS
Article 74
Electronic data exchange formats
Those templates or file format specifications established by the Member States shall, at least, contain the information contained in electronic templates or file format specifications published by the Commission.
When establishing the templates or file-format specifications referred to in the second subparagraph of paragraph 1, Member States may choose one or both of the following options:
file-format specifications based on XML, such as the EU ETS reporting language published by the Commission for use in connection with advanced automated systems;
templates published in a form usable by standard office software, including spreadsheets and word processor files.
Article 75
Use of automated systems
Where a Member State chooses to use automated systems for electronic data exchange based on file-format specifications in accordance with point (a) of Article 74(2), those systems shall ensure in a cost efficient way, through the implementation of technological measures in accordance with the current state of technology:
integrity of data, preventing modification of electronic messages during transmission;
confidentiality of data, through the use of security techniques, including encryption techniques, such that the data is only accessible to the party for which it was intended and that no data can be intercepted by unauthorised parties;
authenticity of data, such that the identity of both the sender and receiver of data is known and verified;
non-repudiation of data, such that one party of a transaction cannot deny having received a transaction nor can the other party deny having sent a transaction, by applying methods such as signing techniques, or independent auditing of system safeguards.
Any automated systems used by Member States based on file-format specifications in accordance with point (a) of Article 74(2) for communication between the competent authority, operator and aircraft operator, as well as verifier and national accreditation body within the meaning of Implementing Regulation (EU) 2018/2067, shall meet the following non-functional requirements, through implementation of technological measures in accordance with the current state of technology:
access control, such that the system is only accessible to authorised parties and no data can be read, written or updated by unauthorised parties, through implementation of technological measures in order to achieve the following:
restriction of physical access to the hardware on which automated systems run through physical barriers;
restriction of logical access to the automated systems through the use of technology for identification, authentication and authorisation;
availability, such that data accessibility is ensured, even after significant time and the introduction of possible new software;
audit trail, such that it is ensured that changes to data can always be found and analysed in retrospect.
CHAPTER VIIa
MONITORING OF EMISSIONS FROM REGULATED ENTITIES
SECTION 1
General provisions
Article 75a
General principles
Articles 4, 5, 6, 7, 8, 9 and 10 of this Regulation shall apply to the emissions, regulated entities and allowances covered by Chapter IVa of Directive 2003/87/EC. For that purpose:
any reference to operator and aircraft operator shall be read as if it were a reference to the regulated entity;
any reference to process emissions shall not be applicable;
any reference to source streams shall be read as if it were a reference to fuel streams;
any reference to emissions source shall not be applicable;
any reference to activities listed in Annex I to Directive 2003/87/EC shall be read as if it were a reference to activity referred to in Annex III to that Directive;
any reference to Article 24 of Directive 2003/87/EC shall be read as if it were a reference to Article 30j of that Directive;
any reference to activity data shall be read as if it were a reference to the released fuel amounts;
any reference to calculation factors shall be read as if it were a reference to calculation factors and scope factor.
Article 75b
Monitoring plans
Article 11, Article 12(2), Articles 13 and 14, Article 15(1) and (2), and Article 16 shall apply. For that purpose:
any reference to operator or aircraft operator shall be read as if it were a reference to the regulated entity;
any reference to aviation activity shall be read as if it were a reference to the activity of the regulated entity.
The monitoring plan shall consist of a detailed, complete and transparent documentation of the monitoring methodology of a specific regulated entity and shall contain at least the elements laid down in Annex I.
Together with the monitoring plan, the regulated entity shall submit the results of a risk assessment providing evidence that the proposed control activities and procedures for control activities are commensurate with the inherent risks and control risks identified.
In accordance with Article 15, significant modifications to the monitoring plan of a regulated entity include:
changes to the category of the regulated entity where such changes require a change in the monitoring methodology or lead to a change of the applicable materiality level pursuant to Article 23 of Implementing Regulation (EU) 2018/2067;
notwithstanding Article 75n, changes regarding whether the regulated entity is considered a ‘regulated entity with low emissions’;
a change in the tier applied;
the introduction of new fuel streams;
a change in the categorisation of fuel streams – between major or de-minimis fuel streams where such a change requires a change to the monitoring methodology;
a change to the default value for a calculation factor, where the value is to be laid down in the monitoring plan;
a change in the default value for the scope factor;
the introduction of new methods or changes to existing methods related to sampling, analysis or calibration, where this has a direct impact on the accuracy of emissions data.
Article 75c
Technical feasibility
Where a regulated entity claims that applying a specific monitoring methodology is technically not feasible, the competent authority shall assess the technical feasibility taking the regulated entity’s justification into account. That justification shall be based on the regulated entity having technical resources capable of meeting the needs of a proposed system or requirement that can be implemented in the required time for the purposes of this Regulation. Those technical resources shall include the availability of the requisite techniques and technology.
For the monitoring and reporting of historical emissions for the year 2024 in accordance with Article 30f(4) of Directive 2003/87/EC, Member States may exempt regulated entities from justifying that a specific monitoring methodology is not technically feasible.
Article 75d
Unreasonable costs
The competent authority shall consider costs unreasonable where the cost estimate exceeds the benefit. To that end, the benefit shall be calculated by multiplying an improvement factor by a reference price of EUR 60 per allowance. The costs shall include an appropriate depreciation period based on the economic lifetime of the equipment.
For the monitoring and reporting of historical emissions for the year 2024 in accordance with Article 30f(4) of Directive 2003/87/EC, Member States may exempt regulated entities from justifying that a specific monitoring methodology would incur unreasonable costs.
In the absence of such data on the average annual emissions caused by that fuel stream over the three most recent years, the regulated entity shall provide a conservative estimate of the annual average emissions, with the exclusion of CO2 stemming from biomass. For measuring instruments under national legal metrological control, the uncertainty currently achieved may be substituted by the maximum permissible error in service allowed by the relevant national legislation.
For the purpose of this paragraph, Article 38(5) shall apply, provided that the relevant information on the sustainability and the greenhouse gas emissions saving criteria of biofuels, bioliquids and biomass fuels used for combustion is available to the regulated entity.
When assessing the unreasonable nature of the costs with regard to the choice of tier levels for the regulated entity’s scope factor determination and with regard to measures increasing the data quality of reported emissions but without direct impact on the accuracy of data on released fuel amounts, the competent authority shall use an improvement factor of 1 % of the average annual emissions of the respective fuel streams in the three most recent reporting periods. The measures increasing the quality of reported emissions but without direct impact on the accuracy of data on released fuel amounts may include:
switching from default values to analyses to determine calculation factors;
an increase of the number of analyses per fuel stream;
where the specific measuring task does not fall under national legal metrological control, the substitution of measuring instruments with instruments complying with relevant requirements of legal metro- logical control of the Member State in similar applications, or to measuring instruments meeting national rules adopted pursuant to Directive 2014/31/EU of the European Parliament and of the Council ( 11 ) or Directive 2014/32/EU;
shortening calibration and maintenance intervals of measuring instruments;
improvements to data-flow activities and control activities that significantly reduce the inherent or control risk;
regulated entities switching to more accurate identification of the scope factor.
Article 75e
Categorisation of regulated entities and fuel streams
The regulated entity shall classify itself in one of the following categories:
a category A entity, where from 2027 to 2030 the average verified annual emissions in the 2 years preceding the reporting period, with the exclusion of CO2 stemming from biomass, are equal to or less than 50 000 tonnes of CO2(e);
a category B entity, where from 2027 to 2030 the average verified annual emissions in the 2 years preceding the reporting period, with the exclusion of CO2 stemming from biomass, are more than 50 000 tonnes of CO2(e).
From 2031 onwards, the category A and B entities referred to in points (a) and (b) of the first subparagraph shall be determined on the basis of the average verified annual emissions in the trading period immediately preceding the current trading period.
By way of derogation from Article 14(2), the competent authority may allow the regulated entity not to modify the monitoring plan where, on the basis of verified emissions, the threshold for the classification of the regulated entity referred to in the first subparagraph is exceeded, but the regulated entity demonstrates to the satisfaction of the competent authority that this threshold has not already been exceeded within the previous five reporting periods and will not be exceeded again in subsequent reporting periods.
The regulated entity shall classify each fuel stream in one of the following categories:
de minimis fuel streams, where the fuel streams selected by the regulated entity jointly account for less than 1 000 tonnes of fossil CO2 per year;
major fuel streams, where the fuel streams do not fall within the category referred to in point (a).
By way of derogation from Article 14(2), the competent authority may allow the regulated entity not to modify the monitoring plan where, on the basis of verified emissions, the threshold for the classification of a fuel stream as a de minimis fuel stream referred to in the first subparagraph is exceeded, but the regulated entity demonstrates to the satisfaction of the competent authority that this threshold has not already been exceeded within the past five reporting periods and will not be exceeded again in subsequent reporting periods.
Article 75f
Monitoring methodology
Each regulated entity shall determine the annual CO2 emissions from activities referred to in Annex III to Directive 2003/87/EC by multiplying for each fuel stream the released fuel amount by the corresponding unit conversion factor, the corresponding scope factor and the corresponding emission factor.
The emission factor shall be expressed as tonnes of CO2 per terajoule (t CO2/TJ) consistent with the use of the unit conversion factor.
The competent authority may allow the use of emission factors for fuels expressed as tCO2/t or tCO2/Nm3. In such cases, the regulated entity shall determine emissions by multiplying the released fuel amount, expressed as tonnes or normal cubic meters, by the corresponding scope factor and the corresponding emission factor.
Article 75g
Temporary changes to the monitoring methodology
The regulated entity shall take all necessary measures to allow the prompt resumption of the application of the monitoring plan as approved by the competent authority.
The regulated entity concerned shall notify the competent authority of the temporary change referred to in paragraph 1 to the monitoring methodology without undue delay to the competent authority, specifying:
the reasons for deviating from the monitoring plan as approved by the competent authority;
the details of the interim monitoring methodology that the regulated entity is using to determine the emissions until the conditions for the application of the monitoring plan as approved by the competent authority have been restored;
the measures the regulated entity is taking to restore the conditions for the application of the monitoring plan as approved by the competent authority;
the anticipated point in time when application of the monitoring plan as approved by the competent authority will be resumed.
SECTION 2
Calculation-based methodology
Article 75h
Applicable tiers for released fuel amounts and calculation factors
When defining the relevant tiers for major fuel streams, to determine the released fuel amounts and each calculation factor, each regulated entity shall apply the following:
at least the tiers listed in Annex V, in the case of a category A entity, or where a calculation factor is required for a fuel stream that is a commercial standard fuel;
in cases other than those referred to in point (a), the highest tier as defined in Annex IIa.
However, for released fuel amounts and calculation factors of major fuel streams the regulated entity may apply a tier up to two levels lower than required in accordance with the first subparagraph, with a minimum of tier 1, where it shows to the satisfaction of the competent authority that the tier required in accordance with the first subparagraph, or where applicable the next highest tier, is technically not feasible or incurs unreasonable costs.
For fuel streams referred to under the first subparagraph, the regulated entity may determine released fuel amounts based on invoices or purchase records, unless a defined tier is achievable without additional effort.
Article 75i
Applicable tiers for the scope factor
However, the regulated entity may apply a tier one level lower than required in accordance with the first subparagraph where it shows to the satisfaction of the competent authority that the tier required in accordance with the first subparagraph is technically not feasible, incurs unreasonable costs, or that methods listed in Article 75l(2), points (a) to (d), are not available.
If the second subparagraph is not applicable, the regulated entity may apply a tier two levels lower than required in accordance with the first subparagraph, with a minimum of tier 1, where it shows to the satisfaction of the competent authority that the tier required in accordance with the first subparagraph is technically not feasible, incurs unreasonable costs, or that, based on a simplified uncertainty assessment, the methods set out in lower tiers lead to a more accurate determination of whether the fuel is used for combustion in sectors covered by Annex III to Directive 2003/87/EC.
Where, for a fuel stream, the regulated entity uses more than one method listed in Article 75l(2), (3) and (4), it shall be required to show that the conditions of this paragraph are met only with respect to the share of the released fuel amount for which the lower tier method is requested.
Article 75j
Determination of released fuel amounts
The regulated entity shall determine the released fuel amounts of a fuel stream in one of the following ways:
where the regulated entities and the fuel streams covered correspond to entities with reporting obligations under and energy products subject to national legislation transposing Directives 2003/96/EC and (EU) 2020/262, on the basis of the measurement methods used for the purposes of those acts when those methods are based on national metrological control;
on the basis of aggregation of measurement of quantities at the point where the fuel streams are released for consumption;
on the basis of continual measurement at the point where the fuel streams are released for consumption.
However, the competent authorities may require the regulated entities to use, where applicable, only the method referred to in the first subparagraph, point (a).
When determining the released fuel amounts in accordance with paragraph 1, point (b) and (c) of this Article, Articles 28 and 29 shall apply, with the exception of Article 28(2), second subparagraph, second sentence and third subparagraph. For that purpose, any reference to operator or installation is to be read as if it were a reference to the regulated entity.
The regulated entity may simplify the uncertainty assessment by assuming that the maximum permissible errors specified for the measuring instrument in service is to be regarded as the uncertainty over the whole reporting period as required by the tier definitions in Annex IIa.
Article 75k
Determination of calculation factors
Article 30, Article 31(1), (2) and (3) and Articles 32, 33, 34, and 35 shall apply. For that purpose:
any reference to operator is to be read as if it were a reference to the regulated entity;
any reference to activity data is to be read as if it were a reference to the released fuel amounts;
any reference to fuels or materials is to be read as if it were a reference to fuels as defined in Article 3(af) of Directive 2003/87/EC;
any reference to Annex II is to be read as if it were a reference to Annex IIa.
The competent authority may require the regulated entity to determine the unit conversion factor and emission factor of fuels as defined in Article 3(af) of Directive 2003/87/EC using the same tiers as required for commercial standard fuels provided that, at the national or regional level, any of the following parameters exhibit a 95 % confidence interval of:
below 2 % for net calorific value;
below 2 % for emission factor, where the released fuel amounts are expressed as energy content.
Before application of this derogation, the competent authority shall submit for the approval of the Commission a summary of the method and data sources used to determine whether one of these conditions is met in the last 3 years and to ensure that the values used are consistent with the average values used by operators at the corresponding national or regional level. The competent authority may collect or request such evidence. At least every 3 years it shall review the values used and notify the Commission if there are any significant changes, taking into account the average of the values used by the operators at the corresponding national or regional level.
The Commission may regularly review the relevance of this provision and the conditions set in this paragraph in light of developments on the fuels market and European standardisation processes.
Article 75l
Determination of the scope factor
Where the released fuel amounts of a fuel stream are used only for combustion in sectors covered by Chapters II and III of Directive 2003/87/EC, with the exception of installations excluded under Article 27a of that Directive, the scope factor shall be set at zero, provided that the regulated entity demonstrates that double counting referred to in Article 30f(5) of Directive 2003/87/EC was avoided.
The regulated entity shall determine a scope factor for each fuel stream either by applying the methods referred to in paragraph 2, or a default value in accordance with paragraph 3, depending on the applicable tier.
The regulated entity shall determine the scope factor on the basis of one or more of the following methods, in accordance with the requirements of the applicable tier as set out in Annex IIa to this Regulation:
methods based on the physical distinction of fuel flows, including methods based on the distinction of geographical region or based on the use of separate measuring instruments;
methods based on the chemical properties of fuels, which allow regulated entities to demonstrate that the relevant fuel can only be used for combustion in specific sectors, due to legal, technical or economic reasons;
use of fiscal marker in accordance with Council Directive 95/60/EC ( 12 );
use of the verified annual emissions report referred to in Article 68(1);
chain of traceable contractual arrangements and invoices (‘chain of custody’), representing the whole supply chain from the regulated entity to the consumers, including final consumers;
use of national markers or colours (dyes) for fuels, based on national legislation;
indirect methods allowing an accurate differentiation of the end uses of the fuels at the time when they are released for consumption, such as sector-specific consumption profiles, typical ranges of capacity of consumers’ fuel consumption levels, and pressure levels such as those of gaseous fuels, provided that the use of that method is approved by the competent authority. The Commission may provide guidelines on applicable indirect methods.
By way of derogation from paragraph 3, the regulated entity may apply a default value lower than 1, provided that:
for the purposes of reporting emissions in the reporting years 2024 to 2026 the regulated entity demonstrates to the satisfaction of the competent authority that using default values lower than 1 leads to a more accurate determination of emissions, or
for the purposes of reporting emissions in the reporting years as from 1 January 2027 the regulated entity demonstrates to the satisfaction of the competent authority that using default values lower than 1 leads to a more accurate determination of emissions and that at least one of the following conditions is met:
the fuel stream is a de-minimis fuel stream;
the default value for the fuel stream is not lower than 0,95 for fuel uses in sectors covered by Annex III to Directive 2003/87/EC or not higher than 0,05 for fuel uses in sectors not covered by that Annex.
When approving the default value in accordance with the first subparagraph, the Commission shall consider the appropriate level of harmonisation of methodologies between Member States, the balance between accuracy, administrative efficiency and cost pass-on implications for consumers, as well as possible risk of evasion of obligations under Chapter IVa of Directive 2003/87/EC.
Any default value for the national fuel stream used under this paragraph shall not be lower than 0,95 for fuel uses in sectors covered by Annex III to Directive 2003/87/EC or not higher than 0,05 for fuel uses in sectors not covered by that Annex.
Article 75m
Release of biomass fuel streams
Article 38 and Article 39, with the exception of paragraphs 2 and 2a, shall apply. For that purpose:
any reference to operator is to be read as if it were a reference to the regulated entity;
any reference to activity data is to be read as if it were a reference to the released fuel amounts;
any reference to source streams is to be read as if it were a reference to fuel streams;
any reference to Annex II is to be read as if it were a reference to Annex IIa;
any reference to paragraph 39(2) is to be read as a reference to paragraph 3 of this Article.
Where, subject to the tier level required, the regulated entity has to carry out analyses to determine the biomass fraction, but the application of the first subparagraph is technically not feasible or would incur unreasonable costs, the regulated entity shall submit an alternative estimation method to determine the biomass fraction to the competent authority for approval.
SECTION 3
Other provisions
Article 75n
Regulated entities with low emissions
The competent authority may consider a regulated entity to be a regulated entity with low emissions where at least one of the following conditions is met:
from 2027 to 2030 the average verified annual emissions in the 2 years preceding the reporting period, with the exclusion of CO2 stemming from biomass, were less than 1 000 tonnes of CO2 per year;
from 2031 the average annual emissions of that regulated entity reported in the verified emissions reports during the trading period immediately preceding the current trading period, with the exclusion of CO2 stemming from biomass, were less than 1 000 tonnes of CO2 per year;
where the average annual emissions referred to in point (a) are not available or no longer representative for the purpose of point (a), but the annual emissions of that regulated entity for the next 5 years, with the exclusion of CO2 stemming from biomass, will be, based on a conservative estimation method, less than 1 000 tonnes of CO2(e) per year.
For the purpose of this paragraph, Article 38(5) shall apply.
The regulated entity shall, without undue delay, submit a significant modification of the monitoring plan within the meaning of Article 15(3), point (b), to the competent authority for approval.
However, the competent authority shall allow that the regulated entity continues simplified monitoring provided that that regulated entity demonstrates to the satisfaction of the competent authority that the threshold referred to in paragraph 2 has not already been exceeded within the past five reporting periods and will not be exceeded again from the following reporting period onwards.
Article 75o
Data management and control
The provisions of Chapter V shall apply. In this regard, any reference to the/an operator shall be read as if it were a reference to the regulated entity.
Article 75p
Annual emission reports
In 2025, the regulated entity shall submit to the competent authority by 30 April an emissions report that covers the annual emissions in 2024. The competent authorities shall ensure that the information provided in that report is in accordance with the requirements of this Regulation.
However, competent authorities may require regulated entities to submit the annual emission reports referred to in this paragraph before 30 April, provided the report is submitted at the earliest 1 month after the deadline set out in Article 68(1).
Article 75q
Reporting on improvements to the monitoring methodology
Regulated entities shall submit to the competent authority for approval a report containing the information referred to in paragraph 2 or 3, where appropriate, by the following deadlines:
for a category A entity, by 31 July every 5 years;
for a category B entity, by 31 July every 3 years;
for any regulated entity that is using the default scope factor as referred to in Article 75l(3) and (4), by 31 July 2026.
However, the competent authority may set an alternative date for submission of the report, but no later date than 30 September of the same year and may approve, together with the monitoring plan or the improvement report, an extension of the deadline applicable pursuant to the second subparagraph, if the regulated entity provides evidence to the satisfaction of the competent authority upon submission of a monitoring plan in accordance with Article 75b or upon notification of updates in accordance with that Article, or upon submission of an improvement report in accordance with this Article, that the reasons for unreasonable costs or for improvement measures being technically not feasible will remain valid for a longer period of time. The extension shall take into account the number of years for which the regulated entity provides evidence. The total time period between improvement reports shall not exceed 4 years for a category B regulated entity or 5 years for a category A regulated entity.
However, where evidence is found that measures needed for reaching those tiers have become technically feasible and do not any more incur unreasonable costs, the regulated entity shall notify the competent authority of appropriate modifications of the monitoring plan in accordance with Article 75b, and submit proposals for implementing the related measures and its timing.
However, where evidence is found that for those fuel streams it has become technically feasible and does not any more incur unreasonable costs to apply any other method referred to in Article 75l(2), the regulated entity shall notify the competent authority of appropriate modifications of the monitoring plan in accordance with Article 75b and submit proposals for implementing the related measures and its timing.
The competent authority may set an alternative date for submission of the report as referred to in this paragraph, but no later date than 30 September of the same year. Where applicable, such report may be combined with the report referred to in paragraph 1 of this Article.
Where recommended improvements would not lead to an improvement of the monitoring methodology, the regulated entity shall provide a justification of why that is the case. Where the recommended improvements would incur unreasonable costs, the regulated entity shall provide evidence of the unreasonable nature of the costs.
Article 75r
Determination of emissions by the competent authority
The competent authority shall make a conservative estimate of the emissions of a regulated entity, taking into account cost pass-on implications for consumers, in any of the following situations:
no verified annual emission report has been submitted by the regulated entity by the deadline required pursuant to Article 75p;
the verified annual emissions report referred to in Article 75p is not in compliance with this Regulation;
the annual emissions report of a regulated entity has not been verified in accordance with Implementing Regulation (EU) 2018/2067.
Article 75s
Access to information and rounding of data
Article 71 and Article 72(1) and (2) shall apply. In this regard, any reference to operators or aircraft operators shall be read as a reference to the regulated entities.
Article 75t
Ensuring consistency with other reporting
For the purposes of reporting emissions of activities listed in Annex III to Directive 2003/87/EC:
the sectors in which the fuels as defined in Article 3, point (af), of Directive 2003/87/EC are released for consumption and are combusted shall be labelled using the CRF codes;
the fuels as defined in Article 3, point (af), of Directive 2003/87/EC shall be labelled using the CN-codes in accordance with national legislation transposing Directives 2003/96/EC and 2009/30/EC, where relevant;
to ensure consistency with reporting for tax purposes pursuant to national legislation transposing Directives 2003/96/EC and (EU) 2020/262, the regulated entity shall use, where relevant, the economic operator registration and identification number pursuant to Regulation (EU) No 952/2013 ( 13 ), the excise number pursuant to Regulation (EU) No 389/2012 ( 14 ) or the national excise registration and identification number issued by the relevant authority pursuant to national legislation transposing Directive 2003/96/EC, when reporting their contact details in the monitoring plan and emission report.
Article 75u
Information technology requirements
The provisions of Chapter VII shall apply. In this regard, any reference to operator and aircraft operator shall be read as if it were a reference to the regulated entity.
CHAPTER VIIb
HORIZONTAL PROVISIONS RELATED TO THE MONITORING OF EMISSIONS FROM REGULATED ENTITIES
Article 75v
Avoiding double counting through monitoring and reporting
Article 75w
Prevention of fraud and obligation to cooperate
CHAPTER VIII
FINAL PROVISIONS
Article 76
Amendments to Regulation (EU) No 601/2012
Regulation (EU) No 601/2012 is amended as follows:
In Article 12(1), third subparagraph, point (a) is replaced by the following:
‘(a) for installations, evidence for each major and minor source stream demonstrating compliance with the uncertainty thresholds for activity data and calculation factors, where applicable, for the applied tiers as defined in Annexes II and IV, as well as for each emission source demonstrating compliance with the uncertainty thresholds for the applied tiers as defined in Annex VIII, where applicable;’
In Article 15, paragraph 4, subparagraph (a) is replaced by the following:
with regard to the emission monitoring plan:
a change of emission factor values laid down in the monitoring plan;
a change between calculation methods as laid down in Annex III, or a change from the use of a calculation method to the use of estimation methodology in accordance with Article 55(2) or vice versa;
the introduction of new source streams;
changes in the status of the aircraft operator as a small emitter within the meaning of Article 55(1) or with regard to one of the thresholds provided by Article 28a(6) of Directive 2003/87/EC;’
Article 49 is replaced by the following:
‘Article 49
Transferred CO2
The operator shall subtract from the emissions of the installation any amount of CO2 originating from fossil carbon in activities covered by Annex I to Directive 2003/87/EC that is not emitted from the installation, but:
transferred out of the installation to any of the following:
a capture installation for the purpose of transport and long-term geological storage in a storage site permitted under Directive 2009/31/EC;
a transport network with the purpose of long-term geological storage in a storage site permitted under Directive 2009/31/EC;
a storage site permitted under Directive 2009/31/EC for the purpose of long-term geological storage;
transferred out of the installation and used to produce precipitated calcium carbonate, in which the used CO2 is chemically bound.
The first subparagraph shall also apply to the receiving installation with respect to the transferring installation's installation identification code.
For the purpose of point (b) of paragraph 1, the operator shall apply a calculation-based methodology.
However, the operator may apply the next lower tier provided that it establishes that applying the highest tier as defined in section 1 of Annex VIII is technically not feasible or incurs unreasonable costs.
For determining the quantity of CO2 chemically bound in precipitated calcium carbonate, the operator shall use data sources representing highest achievable accuracy.
Article 52 is amended as follows:
paragraph 5 is deleted;
paragraph 6 is replaced by the following:
The procedure for informing the use of actual or standard density shall be described in the monitoring plan along with a reference to the relevant aircraft operator documentation.’
paragraph 7 is replaced by the following:
In Article 54, paragraph 2, subparagraph 1 is replaced by the following:
Article 55 is amended as follows:
paragraph 1 is replaced by the following:
paragraphs 2, 3 and 4 are deleted
In Article 59, paragraph 1 is replaced by the following:
‘For the purposes of point (a) of Article 58(3), the operator shall ensure that all relevant measuring equipment is calibrated, adjusted and checked at regular intervals including prior to use, and checked against measurement standards traceable to international measurement standards, where available, in accordance with the requirements of this Regulation and proportionate to the risks identified.
Where components of the measuring systems cannot be calibrated, the operator shall identify those in the monitoring plan and propose alternative control activities.
When the equipment is found not to comply with required performance, the operator shall promptly take necessary corrective action.’
In Article 65(2), a third subparagraph is added:
‘Where the number of flights with data gaps referred to in the first two sub-paragraphs exceed 5 % of the annual flights that are reported, the operator shall inform the competent authority thereof without undue delay and shall take remedial action for improving the monitoring methodology.’
In Annex I, section 2 is amended as follows:
point (2)(b)(ii) is replaced by the following:
‘(ii) procedures for the measurement of fuel uplifts and fuel in tanks, a description of the measuring instruments involved and the procedures for recording, retrieving, transmitting and storing information regarding measurements, as applicable;’
point (2)(b)(iii) is replaced by the following:
‘(iii) the method for the determination of density, where applicable;’
point (2)(b)(iv) is replaced by the following:
‘(iv) justification of the chosen monitoring methodology, in order to ensure lowest levels of uncertainty, according to Article 55 (1);’
point (2)(d) is deleted
point (2)(f) is replaced by the following:
‘(f) a description of the procedures and systems for identifying, assessing and handling data gaps pursuant to Article 65(2).’
In Annex III, section 2 is deleted.
Annex IV is amended as follows:
in section 10, subsection B, the fourth paragraph is deleted;
in section 14, subsection B, the third paragraph is deleted.
Annex IX is amended as follows:
section 1, point (2) is replaced by the following:
‘Documents justifying the selection of the monitoring methodology and the documents justifying temporal or non-temporal changes of monitoring methodologies and, where applicable, tiers approved by the competent authority;’
section 3, point (5) is replaced by the following:
‘(5) Documentation on the methodology for data gaps where applicable, the number of flights where data gaps occurred, the data used for closing the data gaps, where they occurred, and, where the number of flights with data gaps exceeded 5 % of flights that were reported, reasons for the data gaps as well as documentation of remedial actions taken.’
In Annex X, section 2 is amended as follows:
point (7) is replaced by the following:
‘(7) The total number of flights per State pair covered by the report;’
the following point is added below point (7):
‘(7a) Mass of fuel (in tonnes) per fuel type per State pair;’
point (10)(a) is replaced by the following:
‘(a) the number of flights expressed as percentage of annual flights for which data gaps occurred; and the circumstances and reasons for data gaps that apply;’
point (11)(a) is replaced by the following:
‘(a) the number of flights expressed as percentage of annual flights (rounded to the nearest 0,1 %) for which data gaps occurred; and the circumstances and reasons for data gaps that apply;’
Article 77
Repeal of Regulation (EU) No 601/2012
References to the repealed Regulation shall be construed as references to this Regulation and read in accordance with the correlation table in Annex XI.
Article 78
Entry into force and application
This Regulation shall enter into force on the day following that of its publication in the Official Journal of the European Union.
It shall apply from 1 January 2021.
However, Article 76 shall apply from 1 January 2019 or the date of entry into force of this Regulation, whichever is the later.
This Regulation shall be binding in its entirety and directly applicable in all Member States.
ANNEX I
Minimum content of the monitoring plan (Article 12(1))
1. MINIMUM CONTENT OF THE MONITORING PAN FOR INSTALLATIONS
The monitoring plan for an installation shall contain at least the following information:
general information on the installation:
a description of the installation and activities carried out by the installation to be monitored, containing a list of emissions sources and source streams to be monitored for each activity carried out within the installation and meeting the following criteria:
the description must be sufficient for demonstrating that neither data gaps nor double counting of emissions occur;
a simple diagram of the emission sources, source streams, sampling points and metering equipment must be added where requested by the competent authority or where such diagram simplifies describing the installation or referencing emission sources, source streams, measuring instruments and any other parts of the installation relevant for the monitoring methodology including data flow activities and control activities;
a description of the procedure for managing the assignment of responsibilities for monitoring and reporting within the installation, and for managing the competences of responsible personnel;
a description of the procedure for regular evaluation of the monitoring plan's appropriateness, covering at least the following:
checking the list of emissions sources and source streams, ensuring completeness of the emission sources and source streams and that all relevant changes in the nature and functioning of the installation will be included in the monitoring plan;
assessing compliance with the uncertainty thresholds for activity data and other parameters, where applicable, for the applied tiers for each source stream and emission source;
assessing potential measures for improvement of the monitoring methodology applied;
a description of the written procedures of the data flow activities pursuant to Article 58, including a diagram where appropriate for clarification;
a description of the written procedures for the control activities established pursuant to Article 59;
where applicable, information on relevant links with activities undertaken in the framework of the Community eco-management and audit scheme (EMAS) established pursuant to Regulation (EC) No 1221/2009 of the European Parliament and of the Council ( 15 ), systems covered by harmonised standard ►M4 ISO 14001:2015 ◄ and other environmental management systems including information on procedures and controls with relevance to greenhouse gas emissions monitoring and reporting;
the version number of the monitoring plan and the date from which that version of the monitoring plan is applicable;
the category of the installation;
a detailed description of the calculation-based methodologies where applied, consisting of the following:
a detailed description of the calculation-based methodology applied, including a list of input data and calculation formulae used, a list of the tiers applied for activity data and all relevant calculation factors for each of the source streams to be monitored;
where applicable and where the operator intends to make use of simplification for minor and de-minimis source streams, a categorisation of the source streams into major, minor and de-minimis source streams;
a description of the measurement systems used, and their measurement range, specified uncertainty and exact location of the measuring instruments to be used for each of the source streams to be monitored;
where applicable, the default values used for calculation factors indicating the source of the factor, or the relevant source, from which the default factor will be retrieved periodically, for each of the source streams;
where applicable, a list of the analysis methods to be used for the determination of all relevant calculation factors for each of the source streams, and a description of the written procedures for those analyses;
where applicable, a description of the procedure underpinning the sampling plan for the sampling of fuel and materials to be analysed, and the procedure used to revise the appropriateness of the sampling plan;
where applicable, a list of laboratories engaged in carrying out relevant analytical procedures and, where the laboratory is not accredited as referred to in Article 34(1) a description of the procedure used for demonstrating the compliance with equivalent requirements in accordance with Article 34(2) and (3);
where a fall-back monitoring methodology is applied in accordance with Article 22, a detailed description of the monitoring methodology applied for all source streams or emission sources, for which no tier methodology is used, and a description of the written procedure used for the associated uncertainty analysis to be carried out;
a detailed description of the measurement-based methodologies, where applied, including the following:
a description of the measurement method including descriptions of all written procedures relevant for the measurement and the following:
any calculation formulae used for data aggregation and used to determine the annual emissions of each emission source;
the method for determining whether valid hours or shorter reference periods for each parameter can be calculated, and for substitution of missing data in accordance with Article 45;
a list of all relevant emission points during typical operation, and during restrictive and transition phases, including breakdown periods or commissioning phases, supplemented by a process diagram where requested by the competent authority;
where flue gas flow is derived by calculation, a description of the written procedure for that calculation for each emission source monitored using a measurement-based methodology;
a list of all relevant equipment, indicating its measurement frequency, operating range and uncertainty;
a list of applied standards and of any deviations from those standards;
a description of the written procedure for carrying out the corroborating calculations in accordance with Article 46, where applicable;
a description of the method, how CO2 stemming from biomass is to be determined and subtracted from the measured CO2 emissions, and of the written procedure used for that purpose, where applicable;
where applicable and where the operator intends to make use of simplification for minor emission sources, a categorisation of the emission sources into major and minor emission sources;
in addition to elements listed in point 4, a detailed description of the monitoring methodology where N2O emissions are monitored, where appropriate in the form of description of the written procedures applied, including a description of the following:
the method and parameters used to determine the quantity of materials used in the production process and the maximum quantity of material used at full capacity;
the method and parameters used to determine the quantity of product produced as an hourly output, expressed as nitric acid (100 %), adipic acid (100 %), caprolactam, glyoxal and glyoxylic acid per hour respectively;
the method and parameters used to determine the N2O concentration in the flue gas from each emission source, its operating range, and its uncertainty, and details of any alternative methods to be applied where concentrations fall outside the operating range and the situations when this may occur;
the calculation method used to determine N2O emissions from periodic, unabated sources in nitric acid, adipic acid, caprolactam, glyoxal and glyoxylic acid production;
the way in which or the extent to which the installation operates with variable loads, and the manner in which the operational management is carried out;
the method and any calculation formulae used to determine the annual N2O emissions and the corresponding CO2(e) values of each emission source;
information on process conditions that deviate from normal operations, an indication of the potential frequency and the duration of such conditions, as well as an indication of the volume of the N2O emissions during the deviating process conditions such as abatement equipment malfunction;
a detailed description of the monitoring methodology as far as perfluorocarbons from primary aluminium production are monitored, where appropriate in the form of a description of the written procedures applied, including the following:
where applicable, the dates of measurement for the determination of the installation-specific emission factors SEFCF4 or OVC, and FC2F6, and a schedule for future repetitions of that determination;
where applicable, the protocol describing the procedure used to determine the installation-specific emission factors for CF4 and C2F6, showing also that the measurements have been and will be carried out for a sufficiently long time for measured values to converge, but at least for 72 hours;
where applicable, the methodology for determining the collection efficiency for fugitive emissions at installations for primary aluminium production;
a description of cell type and type of anode;
a detailed description of the monitoring methodology where transfer of inherent CO2 as part of a source stream in accordance with Article 48, transfer of CO2 in accordance with Article 49, or transfer of N2O in accordance with Article 50 are carried out, where appropriate in the form of a description of the written procedures applied, including the following:
where applicable, the location of equipment for temperature and pressure measurement in a transport network;
where applicable, procedures for preventing, detecting and quantification of leakage events from transport networks;
in the case of transport networks, procedures effectively ensuring that CO2 is transferred only to installations which have a valid greenhouse gas emission permit, or where any emitted CO2 is effectively monitored and accounted for in accordance with Article 49;
where applicable, a description of continuous measurement systems used at the points of transfer of CO2 or N2O between installations transferring CO2 or N2O or the determination method in accordance with Articles 48, 49 or 50;
where applicable, a description of the conservative estimation method used for determining the biomass fraction of transferred CO2 in accordance with Article 48 or 49;
where applicable, quantification methodologies for emissions or CO2 released to the water column from potential leakages as well as the applied and possibly adapted quantification methodologies for actual emissions or CO2 released to the water column from leakages, as specified in section 23 of Annex IV;
where applicable, a description of the procedure used to assess if biomass source streams comply with Article 38(5);
where applicable, a description of the procedure used to determine biogas quantities based on purchase records in accordance with Article 39(4);
Where applicable, by 31 December 2026, a description of the procedure used to submit information as described in Article 75v(2).
2. ►M4 MINIMUM CONTENT OF MONITORING PLANS FOR AVIATION ◄
The monitoring plan shall contain the following information for all aircraft operators:
the identification of the aircraft operator, call sign or other unique designator used for air traffic control purposes, contact details of the aircraft operator and of a responsible person at the aircraft operator, contact address, the administering Member State, the administering competent authority;
an initial list of aircraft types in its fleet operated at the time of the submission of the monitoring plan and the number of aircraft per type, and an indicative list of additional aircraft types expected to be used including, where available, an estimated number of aircraft per type as well as the source streams (fuel types) associated with each aircraft type;
a description of procedures, systems and responsibilities used to update the completeness of the list of emission sources over the monitoring year for the purpose of ensuring the completeness of monitoring and reporting of the emissions of owned aircraft as well as leased-in aircraft;
a description of the procedures used to monitor the completeness of the list of flights operated under the unique designator by aerodrome pair, and the procedures used for determining whether flights are covered by Annex I to Directive 2003/87/EC for the purpose of ensuring completeness of flights and avoiding double counting;
a description of the procedure for managing and assigning responsibilities for monitoring and reporting, and for managing the competences of responsible personnel;
a description of the procedure for regular evaluation of the monitoring plan's appropriateness, including any potential measures for the improvement of the monitoring methodology and related procedures applied;
a description of the written procedures of the data flow activities as required by Article 58, including a diagram, where appropriate, for clarification;
a description of the written procedures for the control activities established under Article 59;
where applicable, information on relevant links with activities undertaken in the framework of EMAS, systems covered by harmonised standard ►M4 ISO 14001:2015 ◄ and other environmental management systems, including information on procedures and controls with relevance to greenhouse gas emissions monitoring and reporting;
the version number of the monitoring plan and the date from which that version of the monitoring plan is applicable;
confirmation if the aircraft operator intends to make use of the simplification pursuant to Article 28a(6) of Directive 2003/87/EC;
where applicable, a description of the procedure used to assess if biofuel complies with Article 38(5);
where applicable, a description of the procedure used to determine biofuel quantities and to ensure no double counting occurs in accordance with Article 54;
where applicable, a description of the procedure used to assess if eligible aviation fuel complies with Article 54a(2);
where applicable a description of the procedure used to determine eligible aviation fuel quantities and to ensure no double counting according to Article 54a.
The monitoring plan shall contain the following information for aircraft operators which are not small emitters in accordance with Article 55(1) or which do not intend to use a small emitter tool in accordance with Article 55(2):
a description of the written procedure to be used for defining the monitoring methodology for additional aircraft types which an aircraft operator expects to use;
a description of the written procedures for monitoring fuel consumption in every aircraft, including:
the chosen methodology (Method A or Method B) for calculating the fuel consumption; and where the same method is not applied for all aircraft types, a justification for that methodology, as well as a list specifying which method is used under which conditions;
procedures for the measurement of fuel uplifts and fuel in tanks, a description of the measuring instruments involved and the procedures for recording, retrieving, transmitting and storing information regarding measurements, as applicable;
the method for the determination of density, where applicable;
justification of the chosen monitoring methodology, in order to ensure lowest levels of uncertainty, according to Article 56 (1);
a list of deviations for specific aerodromes from the general monitoring methodology as described in point (b) where it is not possible for the aircraft operator due to special circumstances to provide all the required data for the required monitoring methodology;
emission factors used for each fuel type, or in the case of alternative fuels, the methodologies for determining the emission factors, including the methodology for sampling, methods of analysis, a description of the laboratories used and of their accreditation and/or of their quality assurance procedures;
a description of the procedures and systems for identifying, assessing and handling data gaps pursuant to Article 66(2).
▼M4 —————
4. MINIMUM CONTENT OF THE MONITORING PLANS FOR REGULATED ENTITIES
The monitoring plan for regulated entities shall contain at least the following information:
general information on the regulated entity:
the identification of the regulated entity, contact details including address, and where relevant the economic operator registration and identification number pursuant to Regulation (EU) No 952/2013, the excise number pursuant to Regulation (EU) No 389/2012 or the national excise registration and identification number issued by the relevant authority pursuant to national legislation transposing Directive 2003/96/EC, used for reporting for tax purposes pursuant to national legislation transposing Directives 2003/96/EC and (EU) 2020/262;
a description of the regulated entity, containing a list of fuel streams to be monitored, the means through which the fuel streams are released for consumption, the end use(s) of the fuel stream released for consumption including the CRF code, at the level of aggregation available, and meeting the following criteria:
the description is to be sufficient for demonstrating that neither data gaps nor double counting of emissions occur;
a simple diagram of the information referred to in point (b), first subparagraph, describing the regulated entity, the fuel streams, the means through which the fuels as defined in Article 3(af) of Directive 2003/87/EC are released for consumption, measuring instruments and any other parts of the regulated entity relevant for the monitoring methodology including data flow activities and control activities;
where the regulated entities and the fuel streams covered correspond to entities with reporting obligations under and fuels subject to national legislation transposing Directive 2003/96/EC or 2009/30/EC, a simple diagram of the measurement methods used for the purposes of those acts;
where applicable, a description of any deviations from the start and end of the monitoring year in accordance with Article 75j(2);
a description of the procedure for managing the assignment of responsibilities for monitoring and reporting within the regulated entity, and for managing the competences of responsible personnel;
a description of the procedure for regular evaluation of the monitoring plan’s appropriateness, covering at least the following:
checking the list of fuel streams, ensuring completeness and that all relevant changes in the nature and functioning of the regulated entity will be included in the monitoring plan;
assessing compliance with the uncertainty thresholds for released fuel amounts and other parameters, where applicable, for the applied tiers for each fuel stream;
assessing potential measures for improvement of the monitoring methodology applied, in particular the method for determining the scope factor;
a description of the written procedures of the data flow activities pursuant to Article 58, including a diagram where appropriate for clarification;
a description of the written procedures for the control activities established pursuant to Article 59;
where applicable, information on relevant links between the regulated entity’s activity listed in Annex III to Directive 2003/87/EC and reporting for tax purposes pursuant reporting to national legislation transposing Directives 2003/96/EC and (EU) 2020/262;
the version number of the monitoring plan and the date from which that version of the monitoring plan is applicable;
the category of the regulated entity;
a detailed description of the calculation-based methodologies, consisting of the following:
for each fuel stream to be monitored, a detailed description of the calculation-based methodology applied, including a list of input data and calculation formulae used, the methods to determine the scope factor, a list of the tiers applied for released fuel amounts, all relevant calculation factors, the scope factor and, at the level of aggregation known, the CRF-codes of the end use(s) of fuel stream released for consumption;
where the regulated entity intends to make use of simplification for de-minimis fuel streams, a categorisation of the fuel streams into major and de-minimis fuel streams;
a description of the measurement systems used, and their measurement range, uncertainty and location of the measuring instruments to be used for each of the fuel streams to be monitored;
where applicable, the default values used for calculation factors indicating the source of the factor, or the relevant source, from which the default factor will be retrieved periodically, for each of the fuel streams;
where applicable, a list of the analysis methods to be used for the determination of all relevant calculation factors for each of the fuel streams, and a description of the written procedures for those analyses;
where applicable, a description of the procedure explaining the sampling plan for the sampling of fuels to be analysed, and the procedure used to revise the appropriateness of the sampling plan;
where applicable, a list of laboratories engaged in carrying out relevant analytical procedures and, where the laboratory is not accredited as referred to in Article 34(1) a description of the procedure used for demonstrating the compliance with equivalent requirements in accordance with Article 34(2) and (3);
where applicable, a description of the procedure used to assess if biomass fuel streams comply with Article 38(5) and, where relevant, Article 75m(2);
where applicable, a description of the procedure used to determine biogas quantities based on purchase records in accordance with Article 39(4);
where applicable, a description of the procedure used to submit information as described in Article 75v(3) and receive information pursuant to Article 75v(2).
ANNEX II
Tier definitions for calculation-based methodologies related to installations (Article 12(1))
1. DEFINITION OF TIERS FOR ACTIVITY DATA
The uncertainty thresholds in Table 1 shall apply to tiers relevant to activity data requirements in accordance with point (a) of Article 28(1) and the first subparagraph of Article 29(2), and Annex IV, of this Regulation. The uncertainty thresholds shall be interpreted as maximum permissible uncertainties for the determination of source streams over a reporting period.
Where Table 1 does not include activities listed in Annex I to Directive 2003/87/EC and the mass balance is not applied, the operator shall use the tiers listed in Table 1 under ‘Combustion of fuels and fuels used as process input’ for those activities.
Table 1
Tiers for activity data (maximum permissible uncertainty for each tier)
|
Activity/source stream type |
Parameter to which the uncertainty is applied |
Tier 1 |
Tier 2 |
Tier 3 |
Tier 4 |
|
Combustion of fuels and fuels used as process input |
|||||
|
Commercial standard fuels |
Amount of fuel [t] or [Nm3] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Other gaseous and liquid fuels |
Amount of fuel [t] or [Nm3] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Solid fuels, excluding waste |
Amount of fuel [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Waste |
Amount of fuel [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Flaring |
Amount of flare gas [Nm3] |
± 17,5 % |
± 12,5 % |
± 7,5 % |
|
|
Scrubbing: carbonate (Method A) |
Amount carbonate consumed [t] |
± 7,5 % |
|
|
|
|
Scrubbing: gypsum (Method B) |
Amount gypsum produced [t] |
± 7,5 % |
|
|
|
|
Scrubbing: urea |
Amount urea consumed |
± 7,5 % |
|
|
|
|
Refining of mineral oil |
|||||
|
Catalytic cracker regeneration (*1) |
Uncertainty requirements apply separately for each emission source |
± 10 % |
± 7,5 % |
± 5 % |
± 2,5 % |
|
Production of coke |
|||||
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Metal ore roasting and sintering |
|||||
|
Carbonate input and process residues |
Carbonate input material and process residues [t] |
± 5 % |
± 2,5 % |
|
|
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Production of iron and steel |
|||||
|
Fuel as process input |
Each mass flow into and from the installation [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Production of cement clinker |
|||||
|
Kiln input based (Method A) |
Each relevant kiln input [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
|
|
Clinker output (Method B) |
Clinker produced [t] |
± 5 % |
± 2,5 % |
|
|
|
CKD |
CKD or bypass dust [t] |
n.a. (*2) |
± 7,5 % |
|
|
|
Non-carbonate carbon |
Each raw material [t] |
± 15 % |
± 7,5 % |
|
|
|
Production of lime and calcination of dolomite and magnesite |
|||||
|
Carbonates and other process materials (Method A) |
Each relevant kiln input [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
|
|
Alkali earth oxide (Method B) |
Lime produced [t] |
± 5 % |
± 2,5 % |
|
|
|
Kiln dust (Method B) |
Kiln dust [t] |
n.a. (*2) |
± 7,5 % |
|
|
|
Manufacture of glass and mineral wool |
|||||
|
Carbonates and other process materials (input) |
Each carbonate raw material or additives associated with CO2 emissions [t] |
± 2,5 % |
± 1,5 % |
|
|
|
Manufacture of ceramic products |
|||||
|
Carbon inputs (Method A) |
Each carbonate raw material or additive associated with CO2 emissions [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
|
|
Alkali oxide (Method B) |
Gross production including rejected products and cullet from the kilns and shipment [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
|
|
Scrubbing |
Dry CaCO3 consumed [t] |
± 7,5 % |
|
|
|
|
Production of pulp and paper |
|||||
|
Make up chemicals |
Amount of CaCO3 and Na2CO3 [t] |
± 2,5 % |
± 1,5 % |
|
|
|
Production of carbon black |
|||||
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Production of ammonia |
|||||
|
Fuel as process input |
Amount fuel used as process input [t] or [Nm3] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Production of hydrogen and synthesis gas |
|||||
|
Fuel as process input |
Amount fuel used as process input for hydrogen production [t] or [Nm3] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Production of bulk organic chemicals |
|||||
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Production or processing of ferrous and non-ferrous metals, including secondary aluminium |
|||||
|
Process emissions |
Each input material or process residue used as input material in the process [t] |
± 5 % |
± 2,5 % |
|
|
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
Primary aluminium production |
|||||
|
Mass balance methodology |
Each input and output material [t] |
± 7,5 % |
± 5 % |
± 2,5 % |
± 1,5 % |
|
PFC emissions (slope method) |
primary aluminium production in [t], anode effect minutes in [number anode effects/cell day] and [anode effect minutes/ occurrence] |
± 2,5 % |
± 1,5 % |
|
|
|
PFC emissions (overvoltage method) |
primary aluminium production in [t], anode effect overvoltage [mV] and current efficiency [-] |
± 2,5 % |
± 1,5 % |
|
|
|
(*1)
For monitoring emissions from catalytic cracker regeneration (other catalyst regeneration and flexi-cokers) in mineral oil refineries, the required uncertainty is related to the total uncertainty of all emissions from that source.
(*2)
Amount [t] of CKD or bypass dust (where relevant) leaving the kiln system over a reporting period estimated using industry best practice guidelines. |
|||||
2. DEFINITION OF TIERS FOR CALCULATION FACTORS FOR COMBUSTION EMISSIONS
Operators shall monitor CO2 emissions from all types of combustion processes taking place under all activities as listed in Annex I to Directive 2003/87/EC or included in the Union system under Article 24 of that Directive using the tier definitions laid down in this section. ►M1 Where fuels or combustible materials which give rise to CO2 emissions are used as a process input, section 4 of this Annex shall apply. ◄ Where fuels form part of a mass balance in accordance with Article 25(1) of this Regulation, the tier definitions for mass balances in section 3 of this Annex apply.
For process emissions from related exhaust gas scrubbing tier definitions according to sections 4 and 5 of this Annex shall be used, as applicable.
2.1 Tiers for emission factors
Where a biomass fraction is determined for a mixed fuel or material, the tiers defined shall relate to the preliminary emission factor. For fossil fuels and materials the tiers shall relate to the emission factor.
Tier 1: The operator shall apply one of the following:
the standard factors listed in section 1 of Annex VI;
other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in section 1 of Annex VI.
Tier 2a: The operator shall apply country specific emission factors for the respective fuel or material in accordance with points (b) and (c) of Article 31(1) or values in accordance with point (d) of Article 31(1).
Tier 2b: The operator shall derive emission factors for the fuel based on one of the following established proxies, in combination with an empirical correlation as determined at least once per year in accordance with Articles 32 to 35 and 39:
density measurement of specific oils or gases, including those common to the refinery or steel industry;
net calorific value for specific coal types.
The operator shall ensure that the correlation satisfies the requirements of good engineering practice and that it is applied only to values of the proxy which fall into the range for which it was established.
Tier 3: The operator shall apply one of the following:
determination of the emission factor in accordance with the relevant provisions of Articles 32 to 35;
the empirical correlation as specified for Tier 2b, where the operator demonstrates to the satisfaction of the competent authority that the uncertainty of the empirical correlation does not exceed 1/3 of the uncertainty value to which the operator has to adhere with regard to the activity data determination of the relevant fuel or material.
2.2 Tiers for net calorific value (NCV)
Tier 1: The operator shall apply one of the following:
the standard factors listed in section 1 of Annex VI;
other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in section 1 of Annex VI.
Tier 2a: The operator shall apply country specific factors for the respective fuel in accordance with point (b) or (c) of Article 31(1) or values in accordance with point (d) of Article 31(1).
Tier 2b: For commercially traded fuels the net calorific value as derived from the purchasing records for the respective fuel provided by the fuel supplier shall be used provided it has been derived based on accepted national or international standards.
Tier 3: The operator shall determine the net calorific value in accordance with Article 32 to 35.
2.3 Tiers for oxidation factors
Tier 1: The operator shall apply an oxidation factor of 1.
Tier 2: The operator shall apply oxidation factors for the respective fuel in accordance with point (b) or (c) of Article 31(1).
Tier 3: For fuels, the operator shall derive activity-specific factors based on the relevant carbon contents of ashes, effluents and other wastes and by-products, and other relevant incompletely oxidised gaseous forms of carbon emitted except CO. Composition data shall be determined in accordance with Article 32 to 35.
2.4 Tiers for biomass fraction
Tier 1: The operator shall apply an applicable value published by the competent authority or the Commission, or values in accordance with Article 31(1).
Tier 2: The operator shall apply an estimation method approved in accordance with the second subparagraph of Article 39(2).
Tier 3: The operator shall apply analyses in accordance with the first sub-paragraph of Article 39 (2), and in accordance with Articles 32 to 35.
Where an operator assumes a fossil fraction of 100 % in accordance with Article 39(1), no tier shall be assigned for the biomass fraction.
3. DEFINITION OF TIERS FOR CALCULATION FACTORS FOR MASS BALANCES
Where an operator uses a mass balance in accordance with Article 25, it shall use the tier definitions of this section.
3.1 Tiers for carbon content
The operator shall apply one of the tiers listed in this point. For deriving the carbon content from an emission factor, the operator shall use the following equations:
|
(a) |
for emission factors expressed as t CO2/TJ: C = (EF × NCV) / f |
|
(b) |
for emission factors expressed as t CO2/t: C = EF / f |
In those formulae, C is the carbon content expressed as fraction (tonne carbon per tonne product), EF is the emission factor, NCV is the net calorific value, and f is the factor laid down in Article 36(3).
Where a biomass fraction is determined for a mixed fuel or material, the tiers defined shall relate to the total carbon content. The biomass fraction of the carbon shall be determined using the tiers defined in section 2.4 of this Annex.
Tier 1: The operator shall apply one of the following:
the carbon content derived from standard factors listed in Annex VI sections 1 and 2;
other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in Annex VI sections 1 and 2.
Tier 2a: The operator shall derive the carbon content from country specific emission factors for the respective fuel or material in accordance with point (b) or (c) of Article 31(1) or values in accordance with point (d) of Article 31(1).
Tier 2b: The operator shall derive the carbon content from emission factors for the fuel based on one of the following established proxies in combination with an empirical correlation as determined at least once per year in accordance with Articles 32 to 35:
density measurement of specific oils or gases common, for example, to the refinery or steel industry;
net calorific value for specific coals types.
The operator shall ensure that the correlation satisfies the requirements of good engineering practice and that it is applied only to values of the proxy which fall into the range for which it was established.
Tier 3: The operator shall apply one of the following:
determination of the carbon content in accordance with the relevant provisions of Articles 32 to 35;
the empirical correlation as specified for Tier 2b, where the operator demonstrates to the satisfaction of the competent authority that the uncertainty of the empirical correlation does not exceed 1/3 of the uncertainty value to which the operator has to adhere with regard to the activity data determination of the relevant fuel or material.
3.2 Tiers for net calorific values
The tiers defined in section 2.2 of this Annex shall be used.
3.3 Tiers for biomass fraction
The tiers defined in section 2.4 of this Annex shall be used.
4. DEFINITION OF TIERS FOR THE CALCULATION FACTORS FOR CO2 PROCESS EMISSIONS
For all CO2 process emissions, in particular for emissions from the decomposition of carbonates and from process materials containing carbon other than in form of carbonates, including urea, coke and graphite, where they are monitored using the standard methodology in accordance with Article 24(2), the tiers defined in this section for the applicable calculation factors shall be applied.
In case of mixed materials which contain inorganic as well as organic forms of carbon, the operator may choose:
For emissions from the decomposition of carbonates, the operator may choose for each source stream one of the following methods:
Method A (Input based): The emission factor, conversion factor and activity data are related to the amount of material input into the process.
Method B (Output based): The emission factor, conversion factor and activity data are related to the amount of output from the process.
For other CO2 process emissions, the operator shall apply only method A.
4.1. Tiers for the emission factor using Method A
Tier 1: The operator shall apply one of the following:
the standard factors listed in Annex VI section 2 Table 2 in case of carbonate decomposition, or in Tables 1, 4 or 5 for other process materials;
other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in Annex VI.
Tier 2: The operator shall apply a country specific emission factor in accordance with point (b) or (c) of Article 31(1), or values in accordance with point (d) of Article 31(1).
Tier 3: The operator shall determine the emission factor in accordance with Articles 32 to 35. Stoichiometric ratios as listed in section 2 of Annex VI shall be used to convert composition data into emission factors, where relevant.
4.2. Tiers for the conversion factor using Method A
Tier 1: A conversion factor of 1 shall be used.
Tier 2: Carbonates and other carbon leaving the process shall be considered by means of a conversion factor with a value between 0 and 1. The operator may assume complete conversion for one or several inputs and attribute unconverted materials or other carbon to the remaining inputs. The additional determination of relevant chemical parameters of the products shall be carried out in accordance with Articles 32 to 35.
4.3. Tiers for the emission factor using Method B
Tier 1: The operator shall apply one of the following:
the standard factors listed in Annex VI section 2 Table 3.
other constant values in accordance with point (e) of Article 31(1), where no applicable value is contained in Annex VI.
Tier 2: The operator shall apply a country specific emission factor in accordance with point (b) or (c) of Article 31(1), or values in accordance with point (d) of Article 31(1).
Tier 3: The operator shall determine the emission factor in accordance with Articles 32 to 35. Stoichiometric ratios referred to in Annex VI section 2 Table 3 shall be used to convert composition data into emission factors assuming that all of the relevant metal oxides have been derived from respective carbonates. For this purpose the operator shall take into account at least CaO and MgO, and shall provide evidence to the competent authority as to which further metal oxides relate to carbonates in the raw materials.
4.4. Tiers for the conversion factor using Method B
Tier 1: A conversion factor of 1 shall be used.
Tier 2: The amount of non-carbonate compounds of the relevant metals in the raw materials, including return dust or fly ash or other already calcined materials, shall be reflected by means of conversion factors with a value between 0 and 1 with a value of 1 corresponding to a full conversion of raw material carbonates into oxides. The additional determination of relevant chemical parameters of the process inputs shall be carried out in accordance with Articles 32 to 35.
4.5. Tiers for the net calorific value (NCV)
If relevant, the operator shall determine the net calorific value of the process material using the tiers defined in section 2.2 of this Annex. NCV is considered not relevant for de minimis source streams or where the material is not itself combustible without other fuels being added. If in doubt, the operator shall seek confirmation by the competent authority on whether NCV has to be monitored and reported.
4.6. Tiers for the biomass fraction
If relevant, the operator shall determine the biomass fraction of the carbon contained in the process material, using the tiers defined in section 2.4 of this Annex.
▼M1 —————
ANNEX IIa
Tier definitions for calculation-based methodologies related to regulated entities
1. DEFINITION OF TIERS FOR RELEASED FUEL AMOUNTS
The uncertainty thresholds in Table 1 shall apply to tiers relevant to released fuel amounts’ requirements in accordance with Article 28(1), point (a), and Article 29(2), first subparagraph. The uncertainty thresholds shall be interpreted as maximum permissible uncertainties for the determination of fuel streams over a reporting period.
Table 1
Tiers for released fuel amounts (maximum permissible uncertainty for each tier)
|
Fuel stream type |
Parameter to which the uncertainty is applied |
Tier 1 |
Tier 2 |
Tier 3 |
Tier 4 |
Combustion of fuels
|
Commercial standard fuels |
Amount of fuel [t] or [Nm3] or [TJ] |
±7,5 % |
±5 % |
±2,5 % |
±1,5 % |
|
Other gaseous and liquid fuels |
Amount of fuel [t] or [Nm3] or [TJ] |
±7,5 % |
±5 % |
±2,5 % |
±1,5 % |
|
Solid fuels |
Amount of fuel [t] or [TJ] |
±7,5 % |
±5 % |
±2,5 % |
±1,5 % |
2. DEFINITION OF TIERS FOR CALCULATION FACTORS AND THE SCOPE FACTOR
Regulated entities shall monitor CO2 emissions from all types of fuels released for consumption in sectors listed in Annex III to Directive 2003/87/EC or included in the Union system under Article 30j of that Directive using the tier definitions laid down in this section.
2.1. Tiers for emission factors
Where a biomass fraction is determined for a mixed fuel, the tiers defined shall relate to the preliminary emission factor. For fossil fuels, the tiers shall relate to the emission factor.
Tier 1: The regulated entity shall apply one of the following:
the standard factors listed in section 1 of Annex VI;
other constant values in accordance with Article 31(1), point (e), where no applicable value is contained in section 1 of Annex VI.
Tier 2a: The regulated entity shall apply country specific emission factors for the respective fuel in accordance with Article 31(1), points (b) and (c).
Tier 2b: The regulated entity shall derive emission factors for the fuel based on net calorific value for specific coal types, in combination with an empirical correlation as determined at least once per year in accordance with Articles 32 to 35 and 75m.
The regulated entity shall ensure that the correlation satisfies the requirements of good engineering practice and that it is applied only to values of the proxy which fall into the range for which it was established.
Tier 3: The regulated entity shall apply one of the following:
determination of the emission factor in accordance with the relevant provisions of Articles 32 to 35;
the empirical correlation as specified for Tier 2b, where the regulated entity demonstrates to the satisfaction of the competent authority that the uncertainty of the empirical correlation does not exceed 1/3 of the uncertainty value to which the regulated entity has to adhere with regard to the released fuel amounts determination of the relevant fuel.
2.2. Tiers for unit conversion factor
Tier 1: The regulated entity shall apply one of the following:
the standard factors listed in section 1 of Annex VI;
other constant values in accordance with Article 31(1), point (e), where no applicable value is contained in section 1 of Annex VI.
Tier 2a: The regulated entity shall apply country specific factors for the respective fuel in accordance with Article 31(1), point (b) or (c).
Tier 2b: For commercially traded fuels the unit conversion factor as derived from the purchasing records for the respective fuel shall be used provided it has been derived based on accepted national or international standards.
Tier 3: The regulated entity shall determine the unit conversion factor in accordance with Articles 32 to 35.
2.3. Tiers for biomass fraction
Tier 1: The regulated entity shall apply an applicable value published by the competent authority or the Commission, or values in accordance with Article 31(1).
Tier 2: The regulated entity shall apply an estimation method approved in accordance with Article 75m(3), second subparagraph.
Tier 3a: The regulated entity shall apply analyses in accordance with Article 75m(3), first subparagraph, and in accordance with Articles 32 to 35.
Where a regulated entity assumes a fossil fraction of 100 % in accordance with Article 39(1), no tier shall be assigned for the biomass fraction.
Tier 3b: For fuels originating from a production process with defined and traceable input streams, the regulated entity may base the estimation on a mass balance of fossil and biomass carbon entering and leaving the process, such as the mass balance system in accordance with Article 30(1) of Directive (EU) 2018/2001.
2.4. Tiers for the scope factor
Tier 1: The regulated entity shall apply a default value in accordance with Article 75l(3) or (4).
Tier 2: The regulated entity shall apply methods in accordance with Article 75l(2), points (e) to (g).
Tier 3: The regulated entity shall apply methods in accordance with Article 75l(2), points (a) to (d).
ANNEX III
Monitoring methodologies for aviation (Article 53)
1. CALCULATION METHODOLOGIES FOR THE DETERMINATION OF GHGS IN THE AVIATION SECTOR
Method A:
The operator shall use the following formula:
Actual fuel consumption for each flight [t] = Amount of fuel contained in aircraft tanks once fuel uplift for the flight is complete [t] – Amount of fuel contained in aircraft tanks once fuel uplift for subsequent flight is complete [t] + Fuel uplift for that subsequent flight [t]
Where there is no fuel uplift for the flight or subsequent flight, the amount of fuel contained in aircraft tanks shall be determined at block-off for the flight or subsequent flight. In the exceptional case that an aircraft performs activities other than a flight, including undergoing major maintenance involving the emptying of the tanks, after the flight for which fuel consumption is being monitored, the aircraft operator may substitute the quantity ‘Amount of fuel contained in aircraft tanks once fuel uplift for subsequent flight is complete + Fuel uplift for that subsequent flight’ with the ‘Amount of fuel remaining in tanks at the start of the subsequent activity of the aircraft’, as recorded by technical logs.
Method B:
The operator shall use the following formula:
Actual fuel consumption for each flight [t] = Amount of fuel remaining in aircraft tanks at block-on at the end of the previous flight [t] + Fuel uplift for the flight [t] - Amount of fuel contained in tanks at block-on at the end of the flight [t]
The moment of block-on may be considered equivalent to the moment of engine shut down. Where an aircraft does not perform a flight previous to the flight for which fuel consumption is being monitored, the aircraft operator may substitute the quantity ‘Amount of fuel remaining in aircraft tanks at block-on at the end of the previous flight’ with the ‘Amount of fuel remaining in aircraft tanks at the end of the previous activity of the aircraft’, as recorded by technical logs.
2. EMISSION FACTORS FOR STANDARD FUELS
Table 1
Fossil aviation CO2 factors (preliminary emission factors)
|
Fuel |
Emission factor (t CO2/t fuel) |
|
Aviation gasoline (AvGas) |
3,10 |
|
Jet gasoline (Jet B) |
3,10 |
|
Jet kerosene (Jet A1 or Jet A) |
3,16 |
3. CALCULATION OF GREAT CIRCLE DISTANCE
Distance [km] = Great Circle Distance [km] + 95 km
The Great Circle Distance shall be the shortest distance between any two points on the surface of the Earth, which shall be approximated using the system referred to in Article 3.7.1.1 of Annex 15 to the Chicago Convention (WGS 84).
The latitude and longitude of aerodromes shall be taken either from aerodrome location data published in Aeronautical Information Publications (AIP) in compliance with Annex 15 to the Chicago Convention or from a source using AIP data.
Distances calculated by software or by a third party may also be used, provided that the calculation methodology is based on the formula set out in this section, AIP data and WGS 84 requirements.
ANNEX IV
Activity-specific monitoring methodologies related to installations (Article 20(2))
1. SPECIFIC MONITORING RULES FOR EMISSIONS FROM COMBUSTION PROCESSES
A. Scope
Operators shall monitor CO2 emissions from all types of combustion processes taking place under all activities as listed in Annex I to Directive 2003/87/EC or included in the Union system under Article 24 of that Directive including the related scrubbing processes using the rules laid down in this Annex. Any emissions from fuels used as process input shall be treated like combustion emissions with regard to monitoring and reporting methodologies, without prejudice to other classifications applied to emissions.
The operator shall not monitor and report emissions from internal combustion engines for transportation purposes. The operator shall assign all emissions from the combustion of fuels at the installation to the installation, regardless of exports of heat or electricity to other installations. The operator shall not assign emissions associated with the production of heat or electricity that is imported from other installations to the importing installation.
The operator shall include at least the following emission sources: boilers, burners, turbines, heaters, furnaces, incinerators, calciners, kilns, ovens, dryers, engines, fuel cells, chemical looping combustion units, flares, thermal or catalytic post-combustion units, and scrubbers (process emissions) and any other equipment or machinery that uses fuel, excluding equipment or machinery with combustion engines that are used for transportation purposes.
B. Specific monitoring rules
The emissions from combustion processes shall be calculated in accordance with Article 24(1), unless the fuels are included in a mass balance in accordance with Article 25. The tiers defined in section 2 of Annex II shall apply. In addition, process emissions from flue gas scrubbing shall be monitored using the provisions laid down in subsection C.
For emissions from flares special requirements shall apply, as laid down in subsection D of this section.
Combustion processes taking place in gas processing terminals may be monitored using a mass balance in accordance with Article 25.
C. Flue gas scrubbing
C.1 Desulphurisation
Process CO2 emissions from the use of carbonate for acid gas scrubbing from the flue gas stream shall be calculated in accordance with Article 24(2) on the basis of carbonate consumed, Method A as follows, or gypsum produced, Method B as follows. The following applies by way of derogation from section 4 of Annex II.
Method A: Emission factor
Tier 1: The emission factor shall be determined from stoichiometric ratios as laid down in section 2 of Annex VI. The determination of the amount of CaCO3 and MgCO3 or other carbonates in the relevant input material shall be carried out using industry best practice guidelines.
Method B: Emission factor
Tier 1: The emission factor shall be the stoichiometric ratio of dry gypsum (CaSO4 × 2H2O) to CO2 emitted: 0,2558 t CO2/t gypsum.
Conversion Factor:
Tier 1: A conversion factor of 1 shall be used.
C.2 De-NOx
By way of derogation from section 4 of Annex II, process CO2 emissions from the use of urea for scrubbing of the flue gas stream shall be calculated in accordance with Article 24(2) applying the following tiers.
Emission factor:
Tier 1: The determination of the amount of urea in the relevant input material shall be carried out using industry best practice guidelines. The emission factor shall be determined using a stoichiometric ratio of 0,7328 t CO2/t urea.
Conversion Factor:
Only tier 1 shall be applicable.
D. Flares
When calculating emissions from flares the operator shall include routine flaring and operational flaring (trips, start-up and shutdown as well as emergency relieves). The operator shall also include inherent CO2 in accordance with Article 48.
By way of derogation from section 2.1 of Annex II, tiers 1 and 2b for the emission factor shall be defined as follows:
By way of derogation from section 2.3 of Annex II, only tiers 1 and 2 shall be applied for the oxidation factor in the case of flares.
2. REFINING OF MINERAL OIL AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall monitor and report all CO2 emissions from combustion and production processes as occurring in refineries.
The operator shall include at least the following potential sources of CO2 emissions: boilers, process heaters/treaters, internal combustion engines/turbines, catalytic and thermal oxidisers, coke calcining kilns, firewater pumps, emergency/standby generators, flares, incinerators, crackers, hydrogen production units, Claus process units, catalyst regeneration (from catalytic cracking and other catalytic processes) and cokers (flexi-coking, delayed coking).
B. Specific monitoring rules
The monitoring of mineral oil refining activities shall be carried out in accordance with section 1 of this Annex for combustion emissions including flue gas scrubbing. The operator may choose to use the mass balance methodology in accordance with Article 25 for the whole refinery or individual process units such as heavy oil gasification or calcinations plants. Where combinations of standard methodology and mass balance are used, the operator shall provide evidence to the competent authority demonstrating the completeness of emissions covered, and that no double counting of emissions occurs.
Emissions from dedicated hydrogen production units shall be monitored in accordance with section 19 of this Annex.
By way of derogation from Article 24 and 25, emissions from catalytic cracker regeneration, other catalyst regeneration and flexi-cokers shall be monitored using a mass balance, taking into account the state of the input air and the flue gas. All CO in the flue gas shall be accounted for as CO2, applying the mass relation: t CO2 = t CO * 1,571. The analysis of input air and flue gases and the choice of tiers shall be in accordance with the provisions of Articles 32 to 35. The specific calculation methodology shall be approved by the competent authority.
3. PRODUCTION OF COKE AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential sources of CO2 emissions: raw materials (including coal or petroleum coke), conventional fuels (including natural gas), process gases (including blast furnace gas – BFG), other fuels and waste gas scrubbing.
B. Specific monitoring rules
For the monitoring of emissions from the production of coke, the operator may choose to use a mass balance in accordance with Article 25 and section 3 of Annex II, or the standard methodology in accordance with Article 24 and sections 2 and 4 of Annex II.
4. METAL ORE ROASTING AND SINTERING AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential sources of CO2 emissions: raw materials (calcination of limestone, dolomite and carbonatic iron ores, including FeCO3), conventional fuels (including natural gas and coke/coke breeze), process gases (including coke oven gas – COG, and blast furnace gas – BFG), process residues used as input material including filtered dust from the sintering plant, the converter and the blast furnace, other fuels and flue gas scrubbing.
B. Specific monitoring rules
For the monitoring of emissions from metal ore roasting, sintering or pelletisation, the operator may choose to use a mass balance in accordance with Article 25 and section 3 of Annex II or the standard methodology in accordance with Article 24 and sections 2 and 4 of Annex II.
5. PRODUCTION OF PIG IRON AND STEEL AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential sources of CO2 emissions: raw materials (calcination of limestone, dolomite and carbonatic iron ores, including FeCO3), conventional fuels (natural gas, coal and coke), reducing agents (including coke, coal and plastics), process gases (coke oven gas – COG, blast furnace gas – BFG and basic oxygen furnace gas – BOFG), consumption of graphite electrodes, other fuels and waste gas scrubbing.
B. Specific monitoring rules
For the monitoring of emissions from production of pig iron and steel, the operator may choose to use a mass balance in accordance with Article 25 and section 3 of Annex II, or the standard methodology in accordance with Article 24 and sections 2 and 4 of Annex II, at least for a part of the source streams, avoiding any gaps or double counting of emissions.
By way of derogation from section 3.1 of Annex II, tier 3 for the carbon content is defined as follows:
Tier 3: The operator shall derive the carbon content of input or output stream following Articles 32 to 35 in respect to the representative sampling of fuels, products and by-products, the determination of their carbon contents and biomass fraction. The operator shall base the carbon content of products or semi-finished products on annual analyses following Articles 32 to 35 or derive the carbon content from mid-range composition values as specified by relevant international or national standards.
6. PRODUCTION OR PROCESSING OF FERROUS AND NON-FERROUS METALS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall not apply the provisions in this section for the monitoring and reporting of CO2 emissions from the production of pig iron and steel and primary aluminium.
The operator shall consider at least the following potential emission sources for CO2 emissions: conventional fuels; alternative fuels including plastics granulated material from post shredder plants; reducing agents including coke, graphite electrodes; raw materials including limestone and dolomite; carbon containing metal ores and concentrates; and secondary feed materials.
B. Specific monitoring rules
Where carbon stemming from fuels or input materials used at this installation remains in the products or other outputs of the production, the operator shall use a mass balance in accordance with Article 25 and section 3 of Annex II. Where this is not the case the operator shall calculate combustion and process emission separately using the standard methodology in accordance with Article 24 and sections 2 and 4 of Annex II.
Where a mass balance is used, the operator may choose to include emissions from combustion processes in the mass balance or to use the standard methodology in accordance with Article 24 and section 1 of this Annex for a part of the source streams, avoiding any gaps or double counting of emissions.
7. CO2 EMISSIONS FROM PRODUCTION OR PROCESSING OF PRIMARY ALUMINIUM AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall apply the provisions of this section to the monitoring and reporting of CO2 emissions from the production of electrodes for primary aluminium smelting, including stand-alone plants for the production of such electrodes, and the consumption of electrodes during electrolysis.
The operator shall consider at least the following potential sources for CO2 emissions: fuels for the production of heat or steam, electrode production, reduction of Al2O3 during electrolysis which is related to electrode consumption, and use of soda ash or other carbonates for waste gas scrubbing.
The associated emissions of perfluorocarbons – PFCs, resulting from anode effects, including fugitive emissions, shall be monitored in accordance with section 8 of this Annex.
B. Specific monitoring rules
The operator shall determine CO2 emissions from the production or processing of primary aluminium using the mass balance methodology in accordance with Article 25. The mass balance methodology shall consider all carbon in inputs, stocks, products and other exports from the mixing, forming, baking and recycling of electrodes as well as from electrode consumption in electrolysis. Where pre-baked anodes are used, either separate mass balances for production and consumption may be applied, or one common mass balance taking into account both production and consumption of electrodes. In the case of Søderberg cells, the operator shall use one common mass balance.
For emissions from combustion processes the operator may choose to include them in the mass balance or to use the standard methodology in accordance with Article 24 and section 1 of this Annex at least for a part of the source streams, avoiding any gaps or double counting of emissions.
8. PFC EMISSIONS FROM PRODUCTION OR PROCESSING OF PRIMARY ALUMINIUM AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall apply the following for emissions of perfluorocarbons (PFCs) resulting from anode effects including fugitive emissions of PFCs. For associated CO2 emissions, including emissions from electrode production, the operator shall apply section 7 of this Annex. The operator shall furthermore calculate PFC emissions not related to anode effects based on estimation methods in accordance with industry best practice, and any guidelines published by the Commission for this purpose.
B. Determination of PFC emissions
PFC emissions shall be calculated from the emissions measurable in a duct or stack (‘point source emissions’) as well as fugitive emissions using the collection efficiency of the duct:
PFC emissions (total) = PFC emissions (duct) / collection efficiency
The collection efficiency shall be measured when the installation-specific emission factors are determined. For its determination the most recent version of the guidance mentioned under Tier 3 of section 4.4.2.4 of the 2006 IPCC Guidelines shall be used.
The operator shall calculate emissions of CF4 and C2F6 emitted through a duct or stack using one of the following methods:
Method A where the anode effect minutes per cell-day are recorded;
Method B where the anode effect overvoltage is recorded.
Calculation Method A – Slope Method:
The operator shall use the following equations for determining PFC emissions:
Where:
AEM = Anode effect minutes / cell-day;
SEFCF4 = Slope emission factor [(kg CF4 / t Al produced) / (anode effect minutes / cell-day)]. Where different cell-types are used, different SEF may be applied as appropriate;
PrAl = Annual production of primary Aluminium [t];
FC2F6 = Weight fraction of C2F6 (t C2F6 / t CF4).
The anode effect minutes per cell-day shall express the frequency of anode effects (number anode effects / cell-day) multiplied by the average duration of anode effects (anode effect minutes / occurrence):
AEM = frequency × average duration
Emission factor: The emission factor for CF4 (slope emission factor, SEFCF4) expresses the amount [kg] of CF4 emitted per tonne of aluminium produced per anode effect minute / cell-day. The emission factor (weight fraction FC2F6) of C2F6 expresses the amount [t] of C2F6 emitted proportionate to the amount [t] of CF4 emitted.
Tier 1: The operator shall use technology-specific emission factors from Table 1 of this section of Annex IV.
Tier 2: The operator shall use installation-specific emission factors for CF4 and C2F6 established through continuous or intermittent field measurements. For the determination of those emission factors the operator shall use the most recent version of the guidance mentioned under Tier 3 of section 4.4.2.4 of the 2006 IPCC Guidelines ( 17 ). The emission factor shall also take into account emissions related to non-anode effects. The operator shall determine each emission factor with a maximum uncertainty of ± 15 %.
The operator shall determine the emission factors at least every three years or earlier where necessary due to relevant changes at the installation. Relevant changes shall include a change in the distribution of anode effect duration, or a change in the control algorithm affecting the mix of the types of anode effects or the nature of the anode effect termination routine.
Table 1
Technology-specific emission factors related to activity data for the slope method.
|
Technology |
Emission factor for CF4 (SEFCF4) [(kg CF4/t Al) / (AE-Mins/cell-day)] |
Emission factor for C2F6 (FC2F6) [t C2F6/ t CF4] |
|
Centre Worked Prebake (CWPB) |
0,143 |
0,121 |
|
Vertical Stud Søderberg (VSS) |
0,092 |
0,053 |
Calculation Method B – Overvoltage Method:
Where the anode effect overvoltage is measured, the operator shall use the following equations for the determination of PFC emissions:
Where:
OVC = Overvoltage coefficient (‘emission factor’) expressed as kg CF4 per tonne of aluminium produced per mV overvoltage;
AEO = Anode effect overvoltage per cell [mV] determined as the integral of (time × voltage above the target voltage) divided by the time (duration) of data collection;
CE = Average current efficiency of aluminium production [%];
PrAl = Annual production of primary Aluminium [t];
FC2F6 = Weight fraction of C2F6 (t C2F6/t CF4);
The term AEO/CE (Anode effect overvoltage / current efficiency) expresses the time-integrated average anode effect overvoltage [mV overvoltage] per average current efficiency [%].
Emission factor: The emission factor for CF4 (‘overvoltage coefficient’ OVC) shall express the amount [kg] of CF4 emitted per tonne of aluminium produced per millivolt overvoltage [mV]. The emission factor of C2F6 (weight fraction FC2F6) shall express the amount [t] of C2F6 emitted proportionate to the amount [t] of CF4 emitted.
Tier 1:: The operator shall apply technology-specific emission factors from Table 2 of this section of Annex IV.
Tier 2: The operator shall use installation-specific emission factors for CF4 [(kg CF4 / t Al ) / (mV)] and C2F6 [t C2F6/ t CF4] established through continuous or intermittent field measurements. For the determination of those emission factors, the operator shall use the most recent version of the guidance mentioned under Tier 3 of section 4.4.2.4 of the 2006 IPCC Guidelines. The operator shall determine the emission factors with a maximum uncertainty of ± 15 % each.
The operator shall determine the emission factors at least every three years or earlier where necessary due to relevant changes at the installation. Relevant changes shall include a change in the distribution of anode effect duration or a change in the control algorithm affecting the mix of the types of anode effects or the nature of the anode effect termination routine.
Table 2
Technology-specific emission factors related to overvoltage activity data.
|
Technology |
Emission factor for CF4 [(kg CF4/t Al) / mV] |
Emission factor for C2F6 [t C2F6/ t CF4] |
|
Centre Worked Prebake (CWPB) |
1,16 |
0,121 |
|
Vertical Stud Søderberg (VSS) |
N.A. |
0,053 |
C. Determination of CO2(e) emissions
The operator shall calculate CO2(e) emissions from CF4 and C2F6 emissions as follows, using the global warming potentials listed in Annex VI section 3 Table 6:
PFC emissions [t CO2(e)] = CF4 emissions [t] × GWPCF4 + C2F6 emissions [t] × GWPC2F6
9. PRODUCTION OF CEMENT CLINKER AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential sources of CO2 emissions: calcination of limestone in the raw materials, conventional fossil kiln fuels, alternative fossil-based kiln fuels and raw materials, biomass kiln fuels (biomass wastes), non-kiln fuels, non-carbonate carbon content of limestone and shales and raw materials used for waste gas scrubbing.
B. Specific monitoring rules
Emissions from combustion shall be monitored in accordance with section 1 of this Annex. Process emissions from raw meal components shall be monitored in accordance with section 4 of Annex II based on the carbonate content of the process input (calculation Method A) or on the amount of clinker produced (calculation Method B). In case of Method A, carbonates to be taken into account shall at least include CaCO3, MgCO3 and FeCO3. In case of Method B, the operator shall take into account at least CaO and MgO, and shall provide evidence to the competent authority as to which extent further carbon sources have to be taken into account.
CO2 emissions related to dust removed from the process and non-carbonate carbon in the raw materials shall be added in accordance with subsections C and D of this section.
Calculation Method A: Kiln Input Based
Where cement kiln dust (CKD) and bypass dust leave the kiln system the operator shall not consider the related raw material as process input, but calculate emissions from CKD in accordance with subsection C.
Unless the raw meal is characterised, the operator shall apply the uncertainty requirements for activity data separately to each of the relevant carbon-bearing kiln inputs, avoiding double counting or omissions from returned or by-passed materials. Where activity data is determined based on the clinker produced, the net amount of raw meal may be determined by means of a site-specific empirical raw meal/clinker ratio. That ratio shall be updated at least once per year applying industry best practice guidelines.
Calculation Method B: Clinker Output Based
The operator shall determine activity data as the clinker production [t] over the reporting period in one of the following ways:
by direct weighing of clinker;
based on cement deliveries, by material balance taking into account dispatch of clinker, clinker supplies as well as clinker stock variation, using the following formula:
|
clinker produced [t] |
= |
((cement deliveries [t] – cement stock variation [t]) × clinker / cement ratio [t clinker / t cement]) – (clinker supplied [t]) + (clinker dispatched [t]) – (clinker stock variation [t]). |
The operator shall either derive the clinker / cement ratio for each of the different cement products based on the provisions of Articles 32 to 35 or calculate the ratio from the difference of cement deliveries and stock changes and all materials used as additives to the cement including by-pass dust and cement kiln dust.
By way of derogation from section 4 of Annex II, tier 1 for the emission factor shall be defined as follows:
Tier 1: The operator shall apply an emission factor of 0,525 t CO2/t clinker.
C. Emissions Related to Discarded Dust
The operator shall add CO2 emissions, from bypass dust or cement kiln dust (CKD) leaving the kiln system, corrected for a partial calcination ratio of CKD calculated as process emissions in accordance with Article 24(2). By way of derogation from section 4 of Annex II, tiers 1 and 2 for the emission factor shall be defined as follows:
Where:
EFCKD = Emission factor of partially calcined cement kiln dust [t CO2/t CKD];
EFCli = Installation-specific emission factor of clinker [t CO2/t clinker];
d = Degree of CKD calcination (released CO2 as % of total carbonate CO2 in the raw mix).
Tier 3 for the emission factor is not applicable.
D. Emissions from non-carbonate carbon in raw meal
The operator shall determine the emissions from non-carbonate carbon at least from limestone, shale or alternative raw materials (for example, fly ash) used in the raw meal in the kiln in accordance with Article 24(2).
By way of derogation from section 4 of Annex II, the following tier definitions for the emission factor shall apply:
By way of derogation from section 4 of Annex II, the following tier definitions for the conversion factor shall apply:
10. PRODUCTION OF LIME OR CALCINATION OF DOLOMITE OR MAGNESITE AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential sources of CO2 emissions: calcination of limestone, dolomite or magnesite in the raw materials, non-carbonate carbon in raw materials, conventional fossil kiln fuels, alternative fossil-based kiln fuels and raw materials, biomass kiln fuels (biomass wastes) and other fuels.
Where the burnt lime and the CO2 stemming from the limestone are used for purification processes, such that approximately the same amount of CO2 is bound again, the decomposition of carbonates as well as the purification process shall not be required to be included separately in the monitoring plan of the installation.
B. Specific monitoring rules
Emissions from combustion shall be monitored in accordance with section 1 of this Annex. Process emissions from carbonates in raw materials shall be monitored in accordance with section 4 of Annex II. Carbonates of calcium and magnesium shall be always taken into account. Other carbonates and non- carbonate carbon in the raw material shall be taken into account, whenever they are relevant for emission calculation.
For the input-based methodology, carbonate content values shall be adjusted for the respective moisture and gangue content of the material. In the case of magnesia production, other magnesium bearing minerals than carbonates shall be taken into account, as appropriate.
Double counting or omissions resulting from returned or by-pass material shall be avoided. When applying Method B, lime kiln dust shall be considered a separate source stream where relevant.
C. Emissions from non-carbonate carbon in raw materials
The operator shall determine the emissions from non-carbonate carbon at least from limestone, shale or alternative raw materials in the kiln in accordance with Article 24(2).
By way of derogation from section 4 of Annex II, the following tier definitions for the emission factor shall apply:
By way of derogation from section 4 of Annex II, the following tier definitions for the conversion factor shall apply:
11. MANUFACTURE OF GLASS, GLASS FIBRE OR MINERAL WOOL INSULATION MATERIAL AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall apply the provisions in this section also to installations for the production of water glass and stone/rock wool.
The operator shall include at least the following potential sources of CO2 emissions: decomposition of alkali- and alkali earth carbonates as the result of melting the raw material, conventional fossil fuels, alternative fossil-based fuels and raw materials, biomass fuels (biomass wastes), other fuels, carbon containing additives including coke, coal dust and graphite, post-combustion of flue gases and flue gas scrubbing.
B. Specific monitoring rules
Emissions from combustion, including flue gas scrubbing, shall be monitored in accordance with section 1 of this Annex. Process emissions from non-carbonate raw materials, including coke, graphite and coal dust, shall be monitored in accordance with section 4 of Annex II. Carbonates to be taken into account include at least CaCO3, MgCO3, Na2CO3, NaHCO3, BaCO3, Li2CO3, K2CO3, and SrCO3. Only Method A shall be used.
By way of derogation from section 4 of Annex II, the following tier definitions for the emission factor of carbonate-containing raw materials shall apply.
Tier 1: Stoichiometric ratios as listed in section 2 of Annex VI shall be used. The purity of relevant input materials shall be determined by means of industry best practice.
Tier 2: The determination of the amount of relevant carbonates in each relevant input material shall be carried out in accordance with Articles 32 to 35.
By way of derogation from section 4 of Annex II for the conversion factor, only tier 1 shall be applicable for all process emissions from carbonate and non-carbonate containing raw materials.
12. MANUFACTURE OF CERAMIC PRODUCTS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential sources of CO2 emissions: kiln fuels, calcination of limestone/dolomite and other carbonates in the raw material, limestone and other carbonates for reducing air pollutants and other flue gas cleaning, fossil/biomass additives used to induce porosity including polystyrol, residues from paper production or sawdust, non-carbonate carbon content in the clay and other raw materials.
B. Specific monitoring rules
Emissions from combustion including flue gas scrubbing shall be monitored in accordance with section 1 of this Annex. Process emissions from raw meal components and additives shall be monitored in accordance with section 4 of Annex II. For ceramics based on purified or synthetic clays the operator may use either Method A or Method B. For ceramic products based on unprocessed clays and whenever clays or additives with significant non-carbonate carbon content are used, the operator shall use Method A. Carbonates of calcium shall be always taken into account. Other carbonates and non-carbonate carbon in the raw material shall be taken into account, where they are relevant for emission calculation.
Activity data for input materials for Method A may be determined by a suitable back-calculation based on industry best practice and approved by the competent authority. Such back-calculation shall take into account what metering is available for dried green products or fired products, and appropriate data sources for moisture of clay and additives and annealing loss (loss on ignition) of the materials involved.
By way of derogation from section 4 of Annex II, the following tier definitions for emission factors for process emissions of raw materials containing carbonates shall apply:
Method A (Input based):
Tier 1: A conservative value of 0,2 tonnes CaCO3 (corresponding to 0,08794 tonnes of CO2) per tonne of dry clay shall be applied for the calculation of the emission factor instead of results of analyses. All inorganic and organic carbon in the clay material shall be considered as included in this value. Additives shall be considered as not included in this value.
Tier 2: An emission factor for each source stream shall be derived and updated at least once per year using industry best practice reflecting site-specific conditions and the product mix of the installation.
Tier 3: The determination of the composition of the relevant raw materials shall be carried out in accordance with Articles 32 to 35. Stoichiometric ratios as listed in section 2 of Annex VI shall be used to convert composition data into emission factors, where relevant.
Method B (Output based):
Tier 1: A conservative value of 0,123 tonnes of CaO (corresponding to 0,09642 tonnes of CO2) per tonne of product shall be applied for the calculation of the emission factor instead of the results of analyses. All inorganic and organic carbon in the clay material shall be considered as included in this value. Additives shall be considered as not included in this value.
Tier 2: An emission factor shall be derived and updated at least once per year using industry best practice reflecting site-specific conditions and the product mix of the installation.
Tier 3: The determination of the composition of the products shall be carried out in accordance with Articles 32 to 35. Stoichiometric ratios referred to in Annex VI section 2 Table 3 shall be used to convert composition data into emission factors assuming that all of the relevant metal oxides have been derived from respective carbonates, where relevant.
By way of derogation from section 1 of this Annex, for the scrubbing of flue gases the following tier for the emission factor shall apply:
Tier 1: The operator shall apply the stoichiometric ratio of CaCO3 as shown in section 2 of Annex VI.
For scrubbing, no other tier and no conversion factor shall be used. Double counting from used limestone recycled as raw material in the same installation shall be avoided.
13. PRODUCTION OF GYPSUM PRODUCTS AND PLASTER BOARDS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least CO2 emissions from all types of combustion activities.
B. Specific monitoring rules
Emissions from combustion shall be monitored in accordance with section 1 of this Annex.
14. PULP AND PAPER PRODUCTION AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential sources of CO2 emissions: boilers, gas turbines, and other combustion devices producing steam or power, recovery boilers and other devices burning spent pulping liquors, incinerators, lime kilns and calciners, waste gas scrubbing and fuel-fired dryers (such as infrared dryers).
B. Specific monitoring rules
The monitoring of emissions from combustion including flue gas scrubbing shall be carried out in accordance with section 1 of this Annex.
Process emissions from raw materials used as make-up chemicals, including at least limestone or soda ash, shall be monitored by Method A in accordance with section 4 of Annex II. CO2 emissions from the recovery of limestone sludge in pulp production shall be assumed to be recycled biomass CO2. Only the amount of CO2 proportional to the input from make-up chemicals shall be assumed to give rise to fossil CO2 emissions.
For emissions from make-up chemicals, the following tier definitions for the emission factor shall apply:
For the conversion factor, only tier 1 shall be applicable.
15. PRODUCTION OF CARBON BLACK AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least all fuels for combustion and all fuels used as process material as sources for CO2 emissions.
B. Specific monitoring rules
The monitoring of emissions from carbon black production may be monitored either as a combustion process, including flue gas scrubbing, in accordance with section 1 of this Annex or using a mass balance in accordance with Article 25 and section 3 of Annex II.
16. DETERMINATION OF NITROUS OXIDE (N2O) EMISSIONS FROM NITRIC ACID, ADIPIC ACID, CAPROLACTAM, GLYOXAL AND GLYOXYLIC ACID PRODUCTION AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
Each operator shall consider for each activity from which N2O emissions result, all sources emitting N2O from production processes, including where N2O emissions from production are channelled through any abatement equipment. This includes any of the following:
nitric acid production – N2O emissions from the catalytic oxidation of ammonia and/or from the NOx/N2O abatement units;
adipic acid production – N2O emissions including from the oxidation reaction, any direct process venting and/or any emissions control equipment;
glyoxal and glyoxylic acid production – N2O emissions including from the process reactions, any direct process venting and/or any emissions control equipment;
caprolactam production – N2O emissions including from the process reactions, any direct process venting and/or any emissions control equipment.
These provisions shall not apply to any N2O emissions from the combustion of fuels.
B. Determination of N2O emissions
B.1. Annual N2O emissions
The operator shall monitor emissions of N2O from nitric acid production using continuous emissions measurement. The operator shall monitor emissions of N2O from adipic acid, caprolactam, glyoxal and glyoxylic acid production using a measurement-based methodology for abated emissions and a calculation-based method (based on a mass balance methodology) for temporary occurrences of unabated emissions.
For each emission source where continuous emissions measurement is applied, the operator shall consider the total annual emissions to be the sum of all hourly emissions using equation 1 given in section 3 of Annex VIII.
B.2. Hourly N2O emissions
The operator shall calculate annual average hourly N2O emissions for each source where continuous emission measurement is applied using equation 2 given in section 3 of Annex VIII.
The operator shall determine hourly N2O concentrations in the flue gas from each emission source using a measurement-based methodology at a representative point, after the NOx/N2O abatement equipment, where abatement is used. The operator shall apply techniques capable of measuring N2O concentrations of all emission sources during both abated and unabated conditions. Where uncertainties increase during such periods, the operator shall take them into account in the uncertainty assessment.
The operator shall adjust all measurements to a dry gas basis where required and report them consistently.
B.3. Determination of flue gas flow
The operator shall use the methods for monitoring flue gas flow set out in Article 43(5) of this Regulation for measuring the flue gas flow for N2O emissions monitoring. For nitric acid production, the operator shall apply the method in accordance with point (a) of Article 43(5) unless it is technically not feasible. In that case and upon approval by the competent authority, the operator shall apply an alternative method, including by a mass balance methodology based on significant parameters such as ammonia input load, or determination of flow by continuous emissions flow measurement.
The flue gas flow shall be calculated in accordance with the following formula:
Vflue gas flow [Nm3/h] = Vair * (1 – O2, air) / (1 – O2, flue gas)
Where:
Vair = Total input air flow in Nm3/h at standard conditions;
O2, air = Volume fraction of O2 in dry air [= 0,2095];
O2, flue gas = Volume fraction of O2 in the flue gas.
The Vair shall be calculated as the sum of all air flows entering the nitric acid production unit.
The operator shall apply the following formula, unless stated otherwise in its monitoring plan:
Vair = Vprim + Vsec + Vseal
Where:
Vprim = Primary input air flow in Nm3/h at standard conditions;
Vsec = Secondary input air flow in Nm3/h at standard conditions;
Vseal = Seal input air flow in Nm3/h at standard conditions.
The operator shall determine Vprim by continuous flow measurement before the mixing with ammonia takes place. The operator shall determine Vsec by continuous flow measurement, including where the measurement is before the heat recovery unit. For Vseal the operator shall consider the purged airflow within the nitric acid production process.
For input air streams accounting for cumulatively less than 2,5 % of the total air flow, the competent authority may accept estimation methods for the determination of that air flow rate proposed by the operator based on industry best practices.
The operator shall provide evidence through measurements under normal operating conditions that the flue gas flow measured is sufficiently homogeneous to allow for the proposed measurement method. Where non-homogeneous flow is confirmed through these measurements, the operator shall take that into account when determining appropriate monitoring methods and when calculating the uncertainty in the N2O emissions.
The operator shall adjust all measurements to a dry gas basis and report them consistently.
B.4. Oxygen (O2) concentrations
The operator shall measure the oxygen concentrations in the flue gas where necessary for calculating the flue gas flow in accordance with subsection B.3 of this section of Annex IV. In doing so, the operator shall comply with the requirements for concentration measurements within Article 41(1) and (2). In determining the uncertainty of N2O emissions, the operator shall take the uncertainty of O2 concentration measurements into account.
The operator shall adjust all measurements to a dry gas basis where required and report them consistently.
B.5. Calculation of N2O emissions
For specific periods of unabated emissions of N2O from adipic acid, caprolactam, glyoxal and glyoxylic acid production, including unabated emissions from venting for safety reasons and when abatement plant fails, and where continuous emissions monitoring of N2O is technically not feasible, the operator shall subject to the approval of the specific methodology by the competent authority calculate N2O emissions using a mass balance methodology. For this purpose the overall uncertainty shall be similar to the result of applying the tier requirements of Article 41(1) and (2). The operator shall base the calculation method on the maximum potential emission rate of N2O from the chemical reaction taking place at the time and the period of the emission.
The operator shall take the uncertainty in any calculated emissions for a specific emission source into account in determining the annual average hourly uncertainty for the emission source.
B.6. Determination of activity production rates
Production rates shall be calculated using daily production reports and hours of operation.
B.7. Sampling rates
Valid hourly averages or averages for shorter reference periods shall be calculated in accordance with Article 44 for:
concentration of N2O in the flue gas;
total flue gas flow where this is measured directly and where required;
all gas flows and oxygen concentrations necessary to determine the total flue gas flow indirectly.
C. Determination of annual CO2 equivalent – CO2(e)
The operator shall convert the total annual N2O emissions from all emissions sources, measured in tonnes to three decimal places, to annual CO2(e) in rounded tonnes, using the following formula and the GWP values in Annex VI section 3:
CO2(e) [t] = N2Oannual[t] × GWPN2O
Where:
N2Oannual = total annual N2O emissions, calculated according to equation 1 given in section 3 of Annex VIII.
The total annual CO2(e) generated by all emission sources and any direct CO2 emissions from other emission sources included under the greenhouse gas permit shall be added to the total annual CO2 emissions generated by the installation and shall be used for reporting and surrendering allowances.
Total annual emissions of N2O shall be reported in tonnes to three decimal places and as CO2(e) in rounded tonnes.
17. PRODUCTION OF AMMONIA AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential emission sources for CO2 emissions: combustion of fuels supplying the heat for reforming or partial oxidation, fuels used as process input in the ammonia production process (reforming or partial oxidation), fuels used for other combustion processes including for the purpose of producing hot water or steam.
B. Specific monitoring rules
For monitoring of emissions from combustion processes and from fuels used as process inputs, the standard methodology in accordance with Article 24 and section 1 of this Annex shall be applied.
Where CO2 from ammonia production is used as feedstock for the production of urea or other chemicals, or transferred out of the installation for any use not covered by Article 49(1), the related amount of CO2 shall be considered as emitted by the installation producing the CO2.
18. PRODUCTION OF BULK ORGANIC CHEMICALS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall take into account at least the following sources of CO2 emissions: cracking (catalytic and non-catalytic), reforming, partial or full oxidation, similar processes which lead to CO2 emissions from carbon contained in hydrocarbon based feedstock, combustion of waste gases and flaring, and the burning of fuel in other combustion processes.
B. Specific monitoring rules
Where the production of bulk organic chemicals is technically integrated in a mineral oil refinery, the operator of that installation shall apply the relevant provisions of section 2 of this Annex.
Notwithstanding the first subparagraph, the operator shall monitor emissions from combustion processes where the fuels used do not take part in or stem from chemical reactions for the production of bulk organic chemicals using the standard methodology in accordance with Article 24 and section 1 of this Annex. In all other cases, the operator may choose to monitor the emissions from bulk organic chemicals production by mass balance methodology in accordance with Article 25 or the standard methodology in accordance with Article 24. Where using the standard methodology, the operator shall provide evidence to the competent authority that the chosen methodology covers all relevant emissions that would also be covered by a mass-balance methodology.
For the determination of the carbon content under Tier 1, the reference emission factors as listed in Table 5 in Annex VI shall be applied. For substances not listed in Table 5 of Annex VI or other provisions of this Regulation, the operator shall calculate the carbon content from the stoichiometric carbon content in the pure substance and the concentration of the substance in the input or output stream.
19. PRODUCTION OF HYDROGEN AND SYNTHESIS GAS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The operator shall include at least the following potential emission sources for CO2 emissions: fuels used in the hydrogen or synthesis gas production process (reforming or partial oxidation), and fuels used for other combustion processes including for the purpose of producing hot water or steam. Synthesis gas produced shall be considered as source stream under the mass balance methodology.
B. Specific monitoring rules
For monitoring of emissions from combustion processes and from fuels used as process inputs in hydrogen production, the standard methodology in accordance with Article 24 and section 1 of this Annex shall be used.
For the monitoring of emissions from the production of synthesis gas, a mass balance in accordance with Article 25 shall be used. For emissions from separate combustion processes, the operator may choose to include them in the mass balance or to use the standard methodology in accordance with Article 24 at least for a part of the source streams, avoiding any gaps or double counting of emissions.
Where hydrogen and synthesis gas are produced at the same installation, the operator shall calculate CO2 emissions using either separate methodologies for hydrogen and for synthesis gas as outlined in the first two paragraphs of this subsection, or using one common mass balance.
20. PRODUCTION OF SODA ASH AND SODIUM BICARBONATE AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
A. Scope
The emission sources and source streams for CO2 emissions from installations for the production of soda ash and sodium bicarbonate shall include:
fuels used for combustion processes, including fuels used for the purpose of producing hot water or steam;
raw materials, including vent gas from calcination of limestone, to the extent it is not used for carbonation;
waste gases from washing or filtration steps after carbonation, to the extent it is not used for carbonation.
B. Specific monitoring rules
For the monitoring of emissions from the production of soda ash and sodium bicarbonate, the operator shall use a mass balance in accordance with Article 25. For emissions from combustion processes, the operator may choose to include them in the mass balance or to use the standard methodology in accordance with Article 24 at least for a part of the source streams, avoiding any gaps or double counting of emissions.
Where CO2 from the production of soda ash is used for the production of sodium bicarbonate, the amount of CO2 used for producing sodium bicarbonate from soda ash shall be considered as emitted by the installation producing the CO2.
21. DETERMINATION OF GREENHOUSE GAS EMISSIONS FROM CO2 CAPTURE ACTIVITIES FOR THE PURPOSES OF TRANSPORT AND GEOLOGICAL STORAGE IN A STORAGE SITE PERMITTED UNDER DIRECTIVE 2009/31/EC
A. Scope
CO2 capture shall be performed either by a dedicated installation receiving CO2 by transfer from one or more other installations, or by the same installation carrying out the activities producing the captured CO2 under the same greenhouse gas emissions permit. All parts of the installation related to CO2 capture, intermediate storage, transfer to a CO2 transport network or to a site for geological storage of CO2 greenhouse gas emissions shall be included in the greenhouse gas emissions permit and accounted for in the associated monitoring plan. In the case of the installation carrying out other activities covered by Directive 2003/87/EC, the emissions of those activities shall be monitored in accordance with the other relevant sections of this Annex.
The operator of a CO2 capture activity shall at least include the following potential sources of CO2 emission:
CO2 transferred to the capture installation;
combustion and other associated activities at the installation that are related to the capture activity, including fuel and input material use.
B. Quantification of transferred and emitted CO2 amounts
B.1. Installation level quantification
Each operator shall calculate the emissions by taking into account the potential CO2 emissions from all emission relevant processes at the installation, as well as the amount of CO2 captured and transferred to the transport network, using the following formula:
Ecapture installation = Tinput + Ewithout capture – Tfor storage
Where:
Ecapture installation = Total greenhouse gas emissions of the capture installation;
Tinput = Amount of CO2 transferred to the capture installation, determined in accordance with Article 40 to 46 and Article 49.
Ewithout capture = Emissions of the installation assuming the CO2 were not captured, meaning the sum of the emissions from all other activities at the installation, monitored in accordance with relevant sections of Annex IV;
Tfor storage = Amount of CO2 transferred to a transport network or a storage site, determined in accordance with Article 40 to 46 and Article 49.
In cases where CO2 capture is carried out by the same installation as the one from which the captured CO2 originates, the operator shall use zero for Tinput.
In cases of stand-alone capture installations, the operator shall consider Ewithout capture to represent the amount of emissions that occur from other sources than the CO2 transferred to the installation for capture. The operator shall determine those emissions in accordance with this Regulation.
In the case of stand-alone capture installations, the operator of the installation transferring CO2 to the capture installation shall deduct the amount Tinput from the emissions of its installation in accordance with Article 49.
B.2. Determination of transferred CO2
Each operator shall determine the amount of CO2 transferred from and to the capture installation in accordance with Article 49 by means of measurement methodologies carried out in accordance with Articles 40 to 46.
Only where the operator of the installation transferring CO2 to the capture installation demonstrates to the satisfaction of the competent authority that CO2 transferred to the capture installation is transferred in total and to at least equivalent accuracy, may the competent authority allow that operator to use a calculation-based methodology in accordance with Article 24 or 25 to determine the amount Tinput instead of a measurement-based methodology in accordance with Article 40 to 46 and Article 49.
22. DETERMINATION OF GREENHOUSE GAS EMISSIONS FROM THE TRANSPORT OF CO2 BY PIPELINES FOR GEOLOGICAL STORAGE IN A STORAGE SITE PERMITTED UNDER DIRECTIVE 2009/31/EC
A. Scope
The boundaries for monitoring and reporting emissions from CO2 transport by pipeline shall be laid down in the transport network's greenhouse gas emissions permit, including all ancillary plant functionally connected to the transport network, including booster stations and heaters. Each transport network shall have a minimum of one start point and one end point, each connected to other installations carrying out one or more of the activities: capture, transport or geological storage of CO2. Start and end points may include bifurcations of the transport network and cross national borders. Start and end points as well as the installations they are connecting to, shall be laid down in the greenhouse gas emissions permit.
Each operator shall consider at least the following potential emission sources for CO2 emissions: combustion and other processes at installations functionally connected to the transport network including booster stations; fugitive emissions from the transport network; vented emissions from the transport network; and emissions from leakage incidents in the transport network.
B. Quantification Methodologies for CO2
The operator of transport networks shall determine emissions using one of the following methods:
Method A (overall mass balance of all input and output streams) set out in subsection B.1;
Method B (monitoring of emission sources individually) set out in subsection B.2.
In choosing either Method A or Method B, each operator shall demonstrate to the competent authority that the chosen methodology will lead to more reliable results with lower uncertainty of the overall emissions, using best available technology and knowledge at the time of the application for the greenhouse gas emissions permit and approval of the monitoring plan, without incurring unreasonable costs. Where Method B is chosen each operator shall demonstrate to the satisfaction of the competent authority that the overall uncertainty for the annual level of greenhouse gas emissions for the operator's transport network does not exceed 7,5 %.
The operator of a transport network using Method B shall not add CO2 received from another installation permitted in accordance with Directive 2003/87/EC to its calculated level of emissions, and shall not subtract from its calculated level of emissions any CO2 transferred to another installation permitted in accordance with Directive 2003/87/EC.
Each operator of a transport network shall use Method A for the validation of the results of Method B at least once annually. For that validation, the operator may use lower tiers for the application of Method A.
B.1. Method A
Each operator shall determine emissions in accordance with the following formula:
Where:
Emissions = Total CO2 emissions of the transport network [t CO2];
Eown activity = Emissions from the transport network's own activity, meaning not emissions stemming from the CO2 transported, but including emissions from fuel used in booster stations, monitored in accordance with the relevant sections of Annex IV;
TIN,i = Amount of CO2 transferred to the transport network at entry point i, determined in accordance with Articles 40 to 46 and Article 49.
TOUT,i = Amount of CO2 transferred out of the transport network at exit point i, determined in accordance with Articles 40 to 46 and Article 49.
B.2. Method B
Each operator shall determine emissions considering all processes relevant to emissions at the installation as well as the amount of CO2 captured and transferred to the transport facility using the following formula:
Emissions [t CO2] = CO2 fugitive + CO2 vented + CO2 leakage events + CO2 installations
Where:
Emissions = Total CO2 emissions of the transport network [t CO2];
CO2 fugitive = Amount of fugitive emissions [t CO2] from CO2 transported in the transport network, including from seals, valves, intermediate compressor stations and intermediate storage facilities;
CO2 vented = Amount of vented emissions [t CO2] from CO2 transported in the transport network;
CO2 leakage events = Amount of CO2 [t CO2] transported in the transport network, which is emitted as the result of the failure of one or more components of the transport network;
CO2 installations = Amount of CO2 [t CO2] being emitted from combustion or other processes functionally connected to the pipeline transport in the transport network, monitored in accordance with the relevant sections of Annex IV.
B.2.1. Fugitive emissions from the transport network
The operator shall consider fugitive emissions from any of the following types of equipment:
seals;
measurement devices;
valves;
intermediate compressor stations;
intermediate storage facilities.
The operator shall determine average emission factors EF (expressed in g CO2/unit time) per piece of equipment per occurrence where fugitive emissions can be anticipated at the beginning of operation, and by the end of the first reporting year in which the transport network is in operation at the latest. The operator shall review those factors at least every 5 years in the light of the best available techniques and knowledge.
The operator shall calculate fugitive emissions by multiplying the number of pieces of equipment in each category by the emission factor and adding up the results for the single categories as shown in the following equation: