LegalizeCommission 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.)
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
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.
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
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.
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:
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.
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
The operator shall include at least CO2 emissions from all types of combustion activities.
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
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).
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
The operator shall include at least all fuels for combustion and all fuels used as process material as sources for CO2 emissions.
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
Each operator shall consider for each activity from which N2O emissions result, all sources emitting N2O from production processes, including where N2O emissions from production are channelled through any abatement equipment. This includes any of the following:
(a) nitric acid production – N2O emissions from the catalytic oxidation of ammonia and/or from the NOx/N2O abatement units;
(b) adipic acid production – N2O emissions including from the oxidation reaction, any direct process venting and/or any emissions control equipment;
(c) glyoxal and glyoxylic acid production – N2O emissions including from the process reactions, any direct process venting and/or any emissions control equipment;
(d) caprolactam production – N2O emissions including from the process reactions, any direct process venting and/or any emissions control equipment.
These provisions shall not apply to any N2O emissions from the combustion of fuels.
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.
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.
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.
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.
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.
Production rates shall be calculated using daily production reports and hours of operation.
Valid hourly averages or averages for shorter reference periods shall be calculated in accordance with Article 44 for:
(a) concentration of N2O in the flue gas;
(b) total flue gas flow where this is measured directly and where required;
(c) all gas flows and oxygen concentrations necessary to determine the total flue gas flow indirectly.
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
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.
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) of this Regulation, the related amount of CO2 shall be considered as emitted by the installation producing the CO2 , unless the CO2 is bound in a product that satisfies the conditions set out in Article 49a(1) of this Regulation.
18. PRODUCTION OF BULK ORGANIC CHEMICALS AS LISTED IN ANNEX I TO DIRECTIVE 2003/87/EC
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.
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
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.
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
The emission sources and source streams for CO2 emissions from installations for the production of soda ash and sodium bicarbonate shall include:
(a) fuels used for combustion processes, including fuels used for the purpose of producing hot water or steam;
(b) raw materials, including vent gas from calcination of limestone;
(c) waste gases from washing or filtration steps after carbonation.
Emissions from combustion processes, including flue gas scrubbing shall be monitored in accordance with Section 1 of this Annex. Process emissions from raw material components and additives shall be monitored in accordance with Section 4 of Annex II to this Regulation.
Intermediary CO2 for the production of soda ash shall be considered as emitted by the installation producing the CO2, unless the CO2 is bound in a product that satisfies the conditions set out in Article 49a(1) of this Regulation.
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
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, and transfer to a CO2 transport infrastructure or to a site for geological storage of CO2 greenhouse gas emissions, including any functionally connected ancillary facilities, such as CO2 intermediate storage, booster, liquefaction, gasification, purification stations or heaters, shall be included in the greenhouse gas emissions permit and accounted for in the associated monitoring plan. In the case of the installation carrying out other activities covered by Directive 2003/87/EC, the emissions of those activities shall be monitored in accordance with the other relevant sections of this Annex.
The operator of a CO2 capture activity shall at least include the following potential sources of CO2 emission:
(a) CO2 transferred to the capture installation;
(b) combustion and other associated activities at the installation that are related to the capture activity, including fuel and input material use.
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 CO2 infrastructure, using the following formula:
Where:
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 operators of these installations shall take into consideration the following:
(a) 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;
(b) by way of derogation from the monitoring methodology described in this section, the operator may monitor the emissions of the installation by using Method B as described in Section 22 of Annex IV to 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 based either as one or more source streams as in a mass balance methodology in accordance with Article 25 or based on a measurement-based methodology in accordance with Article 49 of this Regulation.
Each operator shall determine the amount of CO2 transferred from and to the capture installation based either as one or more source streams as in a mass balance methodology in accordance with Article 25 or based on a measurement-based methodology in accordance Articles 40 to 46 and Article 49 of this Regulation.
22. DETERMINATION OF GREENHOUSE GAS EMISSIONS FROM THE TRANSPORT OF CO2 FOR GEOLOGICAL STORAGE IN A STORAGE SITE PERMITTED UNDER DIRECTIVE 2009/31/EC
The boundaries for monitoring and reporting emissions from CO2 transport shall be laid down in the CO2 transport infrastructure’s greenhouse gas emissions permit, including all ancillary facilities functionally connected to the transport infrastructure, such as CO2 intermediate storage, booster, liquefaction, gasification, purification stations or heaters. Each transport infrastructure shall have a minimum of one start point and one end point, each connected to other installations or CO2 transport infrastructure carrying out one or more of the activities: capture, transport or geological storage of CO2. Start and end points may be set at bifurcations of the transport infrastructure and at cross national borders. Start and end points as well as the installations or CO2 transport infrastructure they are connecting to, shall be laid down in the greenhouse gas emissions permit.
Each operator of a CO2 transport infrastructure shall consider at least the following potential emission sources for CO2 emissions: combustion and other processes at installations functionally connected to the transport infrastructure including booster stations and liquefaction stations; combustion units, including internal combustion units in CO2 transport vehicles, to the extent emissions are not subject to surrender obligations related to activities listed in Annexes I or III to Directive 2003/87/EC in that same reporting year; fugitive emissions from the transport infrastructure; vented emissions from the transport infrastructure; and emissions from leakage incidents in the transport infrastructure.
CO2 transported for purposes other than for geological storage in a storage site permitted under Directive 2009/31/EC shall not be part of the boundaries for monitoring and reporting emissions by the CO2 transport infrastructure. In cases where the same infrastructure is used for the transport of CO2 for multiple purposes, including for geological storage in a storage site permitted under Directive 2009/31/EC, in a manner where the different consignments cannot be distinguished, the operator of a CO2 transport infrastructure shall indicate this in the greenhouse gas emissions permit and establish a method for recording and documenting the volumes of CO2 transported for purposes other for geological storage in a storage site permitted under Directive 2009/31/EC. The operator of a CO2 transport infrastructure shall monitor emissions resulting from the total volume of CO2 transported but shall report as emitted the share of the emissions corresponding to the volume of CO2 transported for geological storage in a storage site permitted under Directive 2009/31/EC divided by total volume of CO2 transported.
The CO2 transport infrastructure operator shall determine emissions using one of the following methods:
(a) Method A (overall mass balance of all input and output streams) set out in subsection B.1;
(b) Method B (monitoring of emission sources individually) set out in subsection B.2.
The operator shall apply Method B unless the operator can demonstrate to the competent authority that the application of Method A 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 applied, 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 infrastructure does not exceed 7,5 %.
The operator of a CO2 transport infrastructure using Method B shall not add CO2 received from another installation or CO2 transport infrastructure 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 or CO2 transport infrastructure permitted in accordance with Directive 2003/87/EC.
Each operator of a CO2 transport infrastructure 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.
Each operator shall determine emissions in accordance with the following formula:
Emissions [t CO2]=Etransport infrastructure +ΣiTIN,i – ΣiTOUT,i– ΔEin transit
Where:
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 infrastructure using the following formula:
Emissions [t CO2]= E fugitive + Evented + E leakage events + Etransport infrastructue
Where:
The operator of a CO2 transport infrastructure shall consider fugitive emissions from at least any of the following types of equipment:
(a) seals;
(b) measurement devices;
(c) valves;
(d) intermediate compressor stations;
(e) intermediate storage facilities including those mounted onto CO2 transport vehicles.
The operator shall determine average emission rates ER (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 infrastructure is in operation at the latest. The operator shall review those rates 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 rate and adding up the results for the single categories as shown in the following equation:
The number of occurrences (Noccurr) shall be the number of pieces of the given equipment per category, multiplied by the number of time units per year.
The operator of a CO2 transport infrastructure shall provide evidence of the system integrity by using representative (spatial and time-related) temperature and pressure data. Where the data indicates that a leakage has occurred, the operator shall calculate the amount of CO2 leaked with a suitable methodology documented in the monitoring plan, based on industry best practice guidelines, including by use of the differences in temperature and pressure data compared to integrity related average pressure and temperature values.
Each operator of a CO2 transport infrastructure shall provide in the monitoring plan an analysis regarding potential situations of venting emissions, including for maintenance or emergency reasons, and provide a suitable documented methodology for calculating the amount of CO2 vented, based on industry best practice guidelines.
23. GEOLOGICAL STORAGE OF CO2 IN A STORAGE SITE PERMITTED UNDER DIRECTIVE 2009/31/EC
The competent authority shall base the boundaries for monitoring and reporting of emissions from geological storage of CO2 on the delimitation of the storage site and storage complex as specified in the permit pursuant to Directive 2009/31/EC, as well as all ancillary facilities functionally connected to the storage complex, such as CO2 intermediate storage, booster, liquefaction, gasification, purification stations or heaters. Where leakages from the storage complex are identified and lead to emissions or release of CO2 into the water column, the operator shall immediately carry out all the following:
(a) notify the competent authority;
(b) include the leakage as a source stream or an emission source for the respective installation;
(c) monitor and report the emissions.
Only when corrective measures in accordance with Article 16 of Directive 2009/31/EC have been taken and emissions or release into the water column from that leakage can no longer be detected shall the operator delete the respective leakage as emission source from the monitoring plan and no longer monitor and report those emissions.
Each operator of a geological storage activity shall consider at least the following potential emission sources for CO2 overall: fuel use by associated booster stations and other combustion activities including on-site power plants; venting from injection or enhanced hydrocarbon recovery operations; fugitive emissions from injection; breakthrough CO2 from enhanced hydrocarbon recovery operations; and leakages.
The operator of the geological storage activity shall not add CO2 received from another installation to its calculated level of emissions, and shall not subtract from its calculated level of emissions any CO2 which is geologically stored in the storage site or which is transferred to another installation. The operator shall monitor emissions from any ancillary facilities functionally connected to the storage complex in accordance with the provisions set out in Section 22 of Annex IV to this Regulation.
The operator shall determine emissions from venting and fugitive emissions as follows:
CO2 emitted [t CO2 ] = V CO2 [t CO2] + F CO2 [t CO2]
Where:
V CO2 = amount of CO2 vented;
F CO2 = amount of CO2 from fugitive emissions.
Each operator shall determine V CO2 either as one or more source streams as in a mass balance methodology in accordance with Article 25 or by using a measurement-based methodology in accordance with Articles 41 to 46 of this Regulation. By way of derogation from the first sentence and upon approval by the competent authority, the operator may include in the monitoring plan an appropriate methodology for determining V CO2 based on industry best practice, where the application of monitoring methodologies referred to in the first sentence would incur unreasonable costs or the operator can demonstrate that the methodology based on industry best practice allows the amounts to be determined with at least the same accuracy as measurement-based methodologies.
The operator shall consider F CO2 as one source, meaning that the uncertainty requirements associated with the tiers in accordance with section 1 of Annex VIII are applied to the total value instead of the individual emission points. Each operator shall provide in the monitoring plan an analysis regarding potential sources of fugitive emissions, and provide a suitable documented methodology to calculate or measure the amount of F CO2, based on industry best practice guidelines. For the determination of F CO2 the operator may use data collected in accordance with Article 32 to 35 and Annex II(1.1)(e) to (h) of Directive 2009/31/EC for the injection facility, where they comply with the requirements of this Regulation.
Each operator shall consider at least the following potential additional emission sources from enhanced hydrocarbon recovery (EHR):
(a) the oil-gas separation units and gas recycling plant, where fugitive emissions of CO2 could occur;
(b) the flare stack, where emissions might occur due to the application of continuous positive purge systems and during depressurisation of the hydrocarbon production installation;
(c) the CO2 purge system, to avoid high concentrations of CO2 extinguishing the flare.
Each operator shall determine fugitive emissions or vented CO2 in accordance with subsection B.1 of this section of Annex IV.
Each operator shall determine emissions from the flare stack in accordance with subsection D of section 1 of this Annex, taking into account potential inherent CO2 in the flare gas in accordance with Article 48.
Emissions and release to the water column shall be quantified as follows:
Where:
L CO
=
the mass of CO2 emitted or released per calendar day due to the leakage in accordance with all of the following:
(a) for each calendar day for which leakage is monitored, each operator shall calculate L CO2 as the average of the mass leaked per hour [t CO2/h] multiplied by 24;
(b) each operator shall determine the mass leaked per hour in accordance with the provisions in the approved monitoring plan for the storage site and the leakage;
(c) for each calendar day prior to commencement of monitoring, the operator shall take the mass leaked per day to equal the mass leaked per day for the first day of monitoring ensuring no under-estimation occurs;
T
=
the latest of:
(a) the last date when no emissions or release of CO2 into the water column from the source under consideration were reported;
(b) the date the CO2 injection started;
(c) another date such that there is evidence demonstrating to the satisfaction of the competent authority that the emission or release into the water column cannot have started before that date.
Tend = the date by which corrective measures in accordance with Article 16 of Directive 2009/31/EC have been taken and emissions or release of CO2 into the water column can no longer be detected.
The competent authority shall approve and allow the use of other methods for the quantification of emissions or release of CO2 into the water column from leakages where the operator can show to the satisfaction of the competent authority that such methods lead to a higher accuracy than the methodology set out in this subsection.
The operator shall quantify the amount of emissions leaked from the storage complex for each of the leakage events with a maximum overall uncertainty over the reporting period of 7,5 %. Where the overall uncertainty of the applied quantification methodology exceeds 7,5 %, each operator shall apply an adjustment, as follows:
CO2,Reported [t CO2] = CO2,Quantified [t CO2] × (1 + (UncertaintySystem [%]/100) – 0,075)
Where:
CO2,Reported = the amount of CO2 to be included in the annual emission report with regards to the leakage event in question;
CO2,Quantified = the amount of CO2 determined through the used quantification methodology for the leakage event in question;
UncertaintySystem = the level of uncertainty associated with the quantification methodology used for the leakage event in question.
ANNEX V
Minimum tier requirements for calculation-based methodologies involving category A installations referred to in Article 19(2), point (a), and category A entities referred to in Article 75e(2), point (a), and calculation factors for commercial standard fuels used by category B and C installations referred to in Article 19(2), points (b) and (c), and category B entities referred to in Article 75e(2), point (b)
| Activity/Source stream type | Activity data | Emission factor (*1) | Composition data (carbon content) (*1) | Oxidation factor | Conversion factor | |
|---|---|---|---|---|---|---|
| Amount of fuel or material | Net calorific value | |||||
| Combustion of fuels | ||||||
| Commercial standard fuels | 2 | 2a/2b | 2a/2b | n.a. | 1 | n.a. |
| Other gaseous and liquid fuels | 2 | 2a/2b | 2a/2b | n.a. | 1 | n.a. |
| Solid fuels, excluding waste | 1 | 2a/2b | 2a/2b | n.a. | 1 | n.a. |
| Waste | 1 | 2a/2b | 2a/2b | n.a. | 1 | n.a. |
| Mass balance methodology for Gas Processing Terminals | 1 | n.a. | n.a. | 1 | n.a. | n.a. |
| Flares | 1 | n.a. | 1 | n.a. | 1 | n.a. |
| Scrubbing (carbonate) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Scrubbing (gypsum) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Scrubbing (urea) | 1 | 1 | 1 | n.a. | 1 | n.a. |
| Refining of oil | ||||||
| Catalytic cracker regeneration | 1 | n.a. | n.a. | n.a. | n.a. | n.a. |
| Production of coke | ||||||
| Mass balance | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| Fuel as process input | 1 | 2 | 2 | n.a. | n.a. | n.a. |
| Metal ore roasting and sintering | ||||||
| Mass balance | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| Carbonate input | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Production of iron and steel | ||||||
| Mass balance | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| Fuel as process input | 1 | 2a/2b | 2 | n.a. | n.a. | n.a. |
| Production or processing of ferrous and non-ferrous metals, including secondary aluminium | ||||||
| Mass balance | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| Process emissions | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Primary aluminium or alumina production | ||||||
| Mass balance for CO2 emissions | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| PFC emissions (slope method) | 1 | n.a. | 1 | n.a. | n.a. | n.a. |
| PFC emissions (overvoltage method) | 1 | n.a. | 1 | n.a. | n.a. | n.a. |
| Production of cement clinker | ||||||
| Kiln input based (Method A) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Clinker output (Method B) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| CKD | 1 | n.a. | 1 | n.a. | n.a. | n.a. |
| Non-carbonate carbon input | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Production of lime and calcination of dolomite and magnesite | ||||||
| Carbonates (Method A) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Other process inputs | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Alkali earth oxide (Method B) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Manufacture of glass and mineral wool | ||||||
| Carbonate inputs | 1 | n.a. | 1 | n.a. | n.a. | n.a. |
| Other process inputs | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Manufacture of ceramic products | ||||||
| Carbon inputs (Method A) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Other process inputs | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Alkali oxide (Method B) | 1 | n.a. | 1 | n.a. | n.a. | 1 |
| Scrubbing | 1 | n.a. | 1 | n.a. | n.a. | n.a. |
| Production of gypsum and plasterboard: see combustion of fuels | ||||||
| Production of pulp and paper | ||||||
| Make up chemicals | 1 | n.a. | 1 | n.a. | n.a. | n.a. |
| Production of carbon black | ||||||
| Mass balance methodology | 1 | n.a. | n.a. | 1 | n.a. | n.a. |
| Production of ammonia | ||||||
| Fuel as process input | 2 | 2a/2b | 2a/2b | n.a. | n.a. | n.a. |
| Production of bulk organic chemicals | ||||||
| Mass balance | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| Production of hydrogen and synthesis gas | ||||||
| Fuel as process input | 2 | 2a/2b | 2a/2b | n.a. | n.a. | n.a. |
| Mass balance | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| Production of soda ash and sodium bicarbonate | ||||||
| Mass balance | 1 | n.a. | n.a. | 2 | n.a. | n.a. |
| CO2 capture, transfer and geological storage in storage site permitted under Directive 2009/31/EC | ||||||
| Mass balance of CO2 transferred | 2 | n.a. | n.a. | 2 | n.a. | n.a. |
| CO2 venting, leakage, and fugitive emissions | 2 | n.a. | n.a. | 2 | n.a. | n.a. |
| (*1) Tiers for the emission factor relate to the preliminary emission factor, and carbon content relates to the total carbon content. For mixed materials, the biomass fraction must be determined separately. Tier 1 shall be the minimum tier to be applied for the biomass fraction in the case of category A installations and in the case of commercial standard fuels for all installations in accordance with point (a) of Article 26(1). (‘n.a.’ means ‘not applicable’) | ||||||
| Fuels stream type | Amount of fuel released | Unit conversion factor | Emission factor (*1) | |||
| --- | --- | --- | --- | |||
| Commercial standard fuels | 2 | 2a/2b | 2a/2b | |||
| Other gaseous and liquid fuels | 2 | 2a/2b | 2a/2b | |||
| Solid fuels | 1 | 2a/2b | 2a/2b | |||
| (*1) Tiers for the emission factor relate to the preliminary emission factor. For mixed materials, the biomass fraction shall be determined separately. Tier 1 shall be the minimum tier to be applied for the biomass fraction in the case of category A entities and in the case of commercial standard fuels for all regulated entities in accordance with Article 75e(2), point (a) |
ANNEX VI
Reference values for calculation factors (Article 31(1)(a))
1. FUEL EMISSION FACTORS RELATED TO NET CALORIFIC VALUES (NCV)
| Fuel type description | Emission factor (t CO2/TJ) | Net calorific value (TJ/Gg) | Source |
|---|---|---|---|
| Crude oil | 73,3 | 42,3 | IPCC 2006 GL |
| Orimulsion | 77,0 | 27,5 | IPCC 2006 GL |
| Natural gas liquids | 64,2 | 44,2 | IPCC 2006 GL |
| Motor gasoline | 69,3 | 44,3 | IPCC 2006 GL |
| Kerosene (other than jet kerosene) | 71,9 | 43,8 | IPCC 2006 GL |
| Shale oil | 73,3 | 38,1 | IPCC 2006 GL |
| Gas/Diesel oil | 74,1 | 43,0 | IPCC 2006 GL |
| Residual fuel oil | 77,4 | 40,4 | IPCC 2006 GL |
| Liquefied petroleum gases | 63,1 | 47,3 | IPCC 2006 GL |
| Ethane | 61,6 | 46,4 | IPCC 2006 GL |
| Naphtha | 73,3 | 44,5 | IPCC 2006 GL |
| Bitumen | 80,7 | 40,2 | IPCC 2006 GL |
| Lubricants | 73,3 | 40,2 | IPCC 2006 GL |
| Petroleum coke | 97,5 | 32,5 | IPCC 2006 GL |
| Refinery feedstocks | 73,3 | 43,0 | IPCC 2006 GL |
| Refinery gas | 57,6 | 49,5 | IPCC 2006 GL |
| Paraffin waxes | 73,3 | 40,2 | IPCC 2006 GL |
| White spirit and SBP | 73,3 | 40,2 | IPCC 2006 GL |
| Other petroleum products | 73,3 | 40,2 | IPCC 2006 GL |
| Anthracite | 98,3 | 26,7 | IPCC 2006 GL |
| Coking coal | 94,6 | 28,2 | IPCC 2006 GL |
| Other bituminous coal | 94,6 | 25,8 | IPCC 2006 GL |
| Sub-bituminous coal | 96,1 | 18,9 | IPCC 2006 GL |
| Lignite | 101,0 | 11,9 | IPCC 2006 GL |
| Oil shale and tar sands | 107,0 | 8,9 | IPCC 2006 GL |
| Patent fuel | 97,5 | 20,7 | IPCC 2006 GL |
| Coke oven coke and lignite coke | 107,0 | 28,2 | IPCC 2006 GL |
| Gas coke | 107,0 | 28,2 | IPCC 2006 GL |
| Coal tar | 80,7 | 28,0 | IPCC 2006 GL |
| Gas works gas | 44,4 | 38,7 | IPCC 2006 GL |
| Coke oven gas | 44,4 | 38,7 | IPCC 2006 GL |
| Blast furnace gas | 260 | 2,47 | IPCC 2006 GL |
| Oxygen steel furnace gas | 182 | 7,06 | IPCC 2006 GL |
| Natural gas | 56,1 | 48,0 | IPCC 2006 GL |
| Industrial wastes | 143 | n.a. | IPCC 2006 GL |
| Waste oils | 73,3 | 40,2 | IPCC 2006 GL |
| Peat | 106,0 | 9,76 | IPCC 2006 GL |
| Wood/wood waste | — | 15,6 | IPCC 2006 GL |
| Other primary solid biomass | — | 11,6 | IPCC 2006 GL (only NCV) |
| Charcoal | — | 29,5 | IPCC 2006 GL (only NCV) |
| Biogasoline | — | 27,0 | IPCC 2006 GL (only NCV) |
| Biodiesels | — | 27,0 | IPCC 2006 GL (only NCV) |
| Other liquid biofuels | — | 27,4 | IPCC 2006 GL (only NCV) |
| Landfill gas | — | 50,4 | IPCC 2006 GL (only NCV) |
| Sludge gas | — | 50,4 | IPCC 2006 GL (only NCV) |
| Other biogas | — | 50,4 | IPCC 2006 GL (only NCV) |
| Waste tyres | 85,0 (1) | n.a. | WBCSD CSI |
| Municipal waste (non-biomass fraction) | 91,7 | n.a. | IPCC 2006 GL |
| Carbon monoxide | 155,2 (2) | 10,1 | J. Falbe and M. Regitz, Römpp Chemie Lexikon, Stuttgart, 1995 |
| Methane | 54,9 (3) | 50,0 | J. Falbe and M. Regitz, Römpp Chemie Lexikon, Stuttgart, 1995 |
| (1) This value is the preliminary emission factor, i.e. before application of a biomass fraction, if applicable. (2) Based on NCV of 10,12 TJ/t (3) Based on NCV of 50,01 TJ/t |
2. EMISSION FACTORS RELATED TO PROCESS EMISSIONS
| Carbonate | Emission factor [t CO2/ t Carbonate] |
|---|---|
| CaCO3 | 0,440 |
| MgCO3 | 0,522 |
| Na2CO3 | 0,415 |
| BaCO3 | 0,223 |
| Li2CO3 | 0,596 |
| K2CO3 | 0,318 |
| SrCO3 | 0,298 |
| NaHCO3 | 0,524 |
| FeCO3 | 0,380 |
| General | Emission factor = [M(CO2)] / {Y * [M(x)] + Z *[M(CO3 2–)]} X = metal M(x) = molecular weight of X in [g/mol] M(CO2) = molecular weight of CO2 in [g/mol] M(CO3 2–) = molecular weight of CO3 2– in [g/mol] Y = stoichiometric number of X Z = stoichiometric number of CO3 2– |
| Oxide | Emission factor [t CO2/ t Oxide] |
| --- | --- |
| CaO | 0,785 |
| MgO | 1,092 |
| BaO | 0,287 |
| general: XYOZ | Emission factor = [M(CO2)] / {Y * [M(x)] + Z * [M(O)]} X = alkali earth or alkali metal M(x) = molecular weight of X in [g/mol] M(CO2) = molecular weight of CO2 [g/mol] M(O) = molecular weight of O [g/mol]Y Ystoichiometric number of X= 1 (for alkali earth metals)= 2 (for alkali metals) stoichiometric number of X = 1 (for alkali earth metals) = 2 (for alkali metals) Z = stoichiometric number of O = 1 |
| Input or output material | Carbon content (t C/t) |
| --- | --- |
| Direct reduced iron (DRI) | 0,0191 |
| EAF carbon electrodes | 0,8188 |
| EAF charge carbon | 0,8297 |
| Hot briquetted iron | 0,0191 |
| Oxygen steel furnace gas | 0,3493 |
| Petroleum coke | 0,8706 |
| Pig iron | 0,0409 |
| Iron / iron scrap | 0,0409 |
| Steel / steel scrap | 0,0109 |
| (1) IPCC 2006 Guidelines for National Greenhouse Gas Inventories | |
| Substance | Carbon content (t C/t) |
| --- | --- |
| Acetonitril | 0,5852 |
| Acrylonitrile | 0,6664 |
| Butadiene | 0,888 |
| Carbon black | 0,97 |
| Ethylene | 0,856 |
| Ethylene dichloride | 0,245 |
| Ethylene glycol | 0,387 |
| Ethylene oxide | 0,545 |
| Hydrogen cyanide | 0,4444 |
| Methanol | 0,375 |
| Methane | 0,749 |
| Propane | 0,817 |
| Propylene | 0,8563 |
| Vinyl chloride monomer | 0,384 |
| (1) IPCC 2006 Guidelines for National Greenhouse Gas Inventories |
3. GLOBAL WARMING POTENTIALS FOR NON-CO2 GREENHOUSE GASES
| Gas | Global warming potential |
|---|---|
| N2O | 265 t CO2(e)/t N2O |
| CF4 | 6 630 t CO2(e)/t CF4 |
| C2F6 | 11 100 t CO2(e)/t C2F6 |
ANNEX VII
Minimum frequency of analyses (Article 35)
| Fuel/material | Minimum frequency of analyses |
|---|---|
| Natural gas | At least weekly |
| CO2 transferred | At least weekly |
| Flue gas for the purpose of Article 43(4) | Every 50 000 tonnes of total CO2, but at least once a month |
| Other gases, in particular synthesis gas and process gases such as refinery mixed gas, coke oven gas, blast-furnace gas, convertor gas, oilfield and gasfield gas | At least daily — using appropriate procedures at different parts of the day |
| Fuel oils (for example light, medium, heavy fuel oil, bitumen) | Every 20 000 tonnes of fuel and at least six times a year |
| Coal, coking coal, coke, petroleum coke, peat | Every 20 000 tonnes of fuel/material and at least six times a year |
| Other fuels | Every 10 000 tonnes of fuel and at least four times a year |
| Untreated solid waste (pure fossil or mixed biomass/fossil) | Every 5 000 tonnes of waste and at least four times a year |
| Liquid waste, pre-treated solid waste | Every 10 000 tonnes of waste and at least four times a year |
| Carbonate minerals (including limestone and dolomite) | Every 50 000 tonnes of material and at least four times a year |
| Clays and shales | Amounts of material corresponding to 50 000 tonnes of CO2 and at least four times a year |
| Other materials (primary, intermediate and final product) | Depending on the type of material and the variation, amounts of material corresponding to 50 000 tonnes of CO2 and at least four times a year |
ANNEX VIII
Measurement-based methodologies (Article 41)
1. TIER DEFINITIONS FOR MEASUREMENT-BASED METHODOLOGIES
Measurement-based methodologies shall be approved in accordance with tiers with the following maximum permissible uncertainties for the annual average hourly emissions calculated in accordance with Equation 2 set out in section 3 of this Annex.
In case of CO2, the uncertainty is to be applied to the total amount of CO2 measured. Where the biomass fraction is determined using a measurement based methodology, the same tier definition as for CO2 shall be applied to the biomass fraction.
| Tier 1 | Tier 2 | Tier 3 | Tier 4 | |
|---|---|---|---|---|
| CO2 emission sources | ± 10 % | ± 7,5 % | ± 5 % | ± 2,5 % |
| N2O emission sources | ± 10 % | ± 7,5 % | ± 5 % | N.A. |
| CO2 transfer | ± 10 % | ± 7,5 % | ± 5 % | ± 2,5 % |
2. MINIMUM TIER REQUIREMENTS FOR CATEGORY A INSTALLATIONS
| Greenhouse gas | Minimum tier level required |
|---|---|
| CO2 | 2 |
| N2O | 2 |
3. DETERMINATION OF GHGS USING MEASUREMENT-BASED METHODOLOGIES
Equation 1: Calculation of annual emissions in accordance with Article 43(1):
Equation 2: Determination of average hourly emissions:
Equation 2a: Determination of average hourly GHG concentration for the purpose of reporting in accordance with point 9(b) of Annex X, section 1:
Equation 2b: Determination of average hourly flue gas flow for the purpose of reporting in accordance with point 9(b) of Annex X, section 1:
Equation 2c: Calculation of annual emissions for the purpose of the annual emission report in accordance with point 9(b) of Annex X, section 1:
The following abbreviations are used in Equations 1 to 2c:
The index i refers to the individual operating hour. Where an operator uses shorter reference periods in accordance with Article 44(1), that reference period shall be used instead of hours for these calculations.
GHG Emtotal = total annual GHG emissions in tonnes
GHG conchourly, i = hourly concentrations of GHG emissions in g/Nm3 in the flue gas flow measured during operation for hour i;
Vhourly, i = flue gas volume in Nm3 for hour i (i.e. integrated flow over the hour or shorter reference period);
GHG Emaverage = annual average hourly emissions in kg/h from the source;
HoursOp = total number of hours for which the measurement-based methodology is applied, including the hours for which data has been substituted in accordance with Article 45(2) to (4);
GHG concaverage = annual average hourly concentrations of GHG emissions in g/Nm3;
Flowaverage = annual average flue gas flow in Nm3/h.
4. CALCULATION OF THE CONCENTRATION USING INDIRECT CONCENTRATION MEASUREMENT
Equation 3: Calculation of the concentration
5. SUBSTITUTION FOR MISSING CONCENTRATION DATA FOR MEASUREMENT-BASED METHODOLOGIES
Equation 4: Substitution for missing data for measurement-based methodologies
Where:
σC_ = the best estimate of the standard deviation of the concentration of the specific parameter over the whole reporting or, where specific circumstances applied when data loss occurred, an appropriate period reflecting the specific circumstances.
ANNEX IX
Operators, aircraft operators and regulated entities shall retain at least the following:
1. COMMON ELEMENTS FOR INSTALLATIONS, AIRCRAFT OPERATORS AND REGULATED ENTITIES
(1) The monitoring plan approved by the competent authority;
(2) 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;
(3) All relevant updates of monitoring plans notified to the competent authority in accordance with Article 15, and the competent authority’s replies;
(4) All written procedures referred to in the monitoring plan, including the sampling plan where relevant, the procedures for data flow activities and the procedures for control activities;
(5) A list of all versions used of the monitoring plan and all related procedures;
(6) Documentation of the responsibilities in connection to the monitoring and reporting;
(7) The risk assessment performed by the operator, aircraft operator or regulated entity, where applicable;
(8) The improvement reports in accordance with Article 69;
(9) The verified annual emission report;
(10) The verification report;
(11) Any other information that is identified as required for the verification of the annual emissions report.
2. SPECIFIC ELEMENTS FOR STATIONARY INSTALLATIONS
(1) The greenhouse gas emissions permit, and any updates thereof;
(2) Any uncertainty assessments, where applicable;
(3) For calculation-based methodologies applied in installations: (a) the activity data used for any calculation of the emissions for each source stream, categorised according to process and fuel or material type; (b) a list of all default values used as calculation factors, where applicable; (c) the full set of sampling and analysis results for the determination of calculation factors; (d) documentation about all ineffective procedures corrected and correction action taken in accordance with Article 64; (e) any results of calibration and maintenance of measuring instruments.
(4) For measurement-based methodologies in installations, the following additional elements: (a) documentation justifying the selection of a measurement-based methodology; (b) the data used for the uncertainty analysis of emissions from each emission source, categorised according to process; (c) the data used for the corroborating calculations and results of the calculations; (d) a detailed technical description of the continuous measurement system including the documentation of the approval from the competent authority; (e) raw and aggregated data from the continuous measurement system, including documentation of changes over time, the log-book on tests, down-times, calibrations, servicing and maintenance; (f) documentation of any changes to the continuous measurement system; (g) any results of the calibration and maintenance of measuring instruments; (h) where applicable, the mass or energy balance model used for the purpose of determining surrogate data in accordance with Article 45(4) and underlying assumptions;
(5) Where a fall-back methodology as referred to in Article 22 is applied, all data necessary for determining the emissions for the emission sources and source streams for which that methodology is applied, as well as proxy data for activity data, calculation factors and other parameters which would be reported under a tier methodology;
(6) For primary aluminium or alumina production, the following additional elements: (a) documentation of results from measurement campaigns for the determination of the installation specific emission factors for CF4 and C2F6; (b) documentation of the results of the determination of the collection efficiency for fugitive emissions; (c) all relevant data on primary aluminium production, anode effect frequency and duration or overvoltage data;
(7) For CO2 capture, transport and geological storage activities, where applicable, the following additional elements: (a) documentation of the amount of CO2 injected into the storage complex by installations carrying out geological storage of CO2; (b) representatively aggregated pressure and temperature data from a transport infrastructure; (c) a copy of the storage permit, including the approved monitoring plan, pursuant to Article 9 of Directive 2009/31/EC; (d) the reports submitted in accordance with Article 14 of Directive 2009/31/EC; (e) reports on the results of the inspections carried out in accordance with Article 15 of Directive 2009/31/EC; (f) documentation on corrective measures taken in accordance with Article 16 of Directive 2009/31/EC.
(8) For CO2 permanently chemically bound, where applicable, the following additional elements: (a) documentation of the amount of CO2 permanently chemically bound; (b) the types of products the CO2 was chemically bound, their amounts produced and the respective uses of the products;
3. SPECIFIC ELEMENTS FOR AVIATION ACTIVITIES
(1) A list of aircraft owned, leased-in and leased-out, and necessary evidence for the completeness of that list; for each aircraft the date when it is added to or removed from the aircraft operator’s fleet;
(2) A list of flights covered in each reporting period including, for each flight, the ICAO designator of the two aerodromes, and necessary evidence for the completeness of that list;
(3) Relevant data used for determining the fuel consumption and emissions;
(4) For the purposes of monitoring emission, 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;
(5) For the purpose of monitoring and reporting of non-CO2 aviation effects, all data monitored by the aircraft operator pursuant to Article 56b(2) of this Regulation, where such data is used to calculate the CO2(e) per flight in accordance with the method referred to in Article 56a of this Regulation;
(6) For the purpose of monitoring non-CO2 aviation effects and where the aircraft operator does not use NEATS, the number of flights where data gaps occurred and appropriate default values used of Annex IIIa, Section 5 and Annex IIIb to this Regulation for closing the data gaps.
4. SPECIFIC ELEMENTS FOR REGULATED ENTITIES
(1) A list of fuel streams in each reporting period and necessary evidence for completeness of that list, including the categorisation of fuel streams;
(2) the means through which the fuels as defined in Article 3, point (af) of Directive 2003/87/EC are released for consumption and where available, the types of intermediate consumers, where this would not cause disproportionate administrative burden;
(3) the type of end use, including the relevant CRF code of the final sectors in which the fuel as defined in Article 3, point (af), of Directive 2003/87/EC is consumed, at the level of aggregation available;
(4) relevant data used for determining the released fuel amounts for each fuel stream;
(5) a list of default values used and calculation factors, where applicable;
(6) the scope factor for each fuel stream, including an identification of each final consumption sector and all relevant underlying data for this identification;
(7) the tiers applicable including justifications for deviation from required tiers;
(8) the full set of sampling and analysis results for the determination of calculation factors;
(9) documentation about all ineffective procedures corrected and correction action taken in accordance with Article 64;
(10) any results of calibration and maintenance of measuring instruments;
(11) a list of installations to which fuel as defined in Article 3 (af) of Directive 2003/87/EC is released for consumption, including names, address and permit number and released fuel amounts supplied to those installations for the reporting periods.
ANNEX X
Minimum content of Annual Reports (Article 68(3))
1. ANNUAL EMISSION REPORTS OF STATIONARY INSTALLATIONS
The annual emission report of an installation shall at least contain the following information:
(1) Data identifying the installation, as specified in Annex IV to Directive 2003/87/EC, and its unique permit number except for installations for the incineration of municipal waste;
(2) Name and address of the verifier of the report;
(3) The reporting year;
(4) Reference to and version number of the latest approved monitoring plan and the date from which it is applicable, as well as reference to and version number of any other monitoring plans relevant for the reporting year;
(5) Relevant changes in the operations of an installation and changes as well as temporary deviations that occurred during the reporting period to the monitoring plan approved by the competent authority; including temporal or permanent changes of tiers, reasons for those changes, starting date for the changes, and starting and ending dates of temporal changes;
(6) Information for all emissions sources and source streams consisting of at least: (a) the total emissions expressed as t CO2(e), including CO2 from biomass source streams which do not comply with Article 38(5) of this Regulation, or from RFNBO or RCF source streams which do not comply with Article 39a(3) of this Regulation, or from synthetic low-carbon fuels source streams which do not comply with Article 39a(4) of this Regulation; (b) where greenhouse gases other than CO2 are emitted, the total emissions expressed as t; (c) whether the measurement or the calculation methodology referred to in Article 21 is applied; (d) the tiers applied; (e) activity data: (i) in the case of fuels the amount of fuel (expressed as tonnes or Nm3) and the net calorific value (GJ/t or GJ/ Nm3) reported separately; (ii) for all other source streams the amount expressed as tonnes or Nm3; (f) emission factors, expressed in accordance with the requirements set out in Article 36(2) of this Regulation; biomass fraction; zero-rated biomass fraction, RFNBO or RCF fraction, zero-rated RFNBO or RCF fraction, synthetic low-carbon fraction, zero-rated synthetic low-carbon fraction, oxidation and conversion factors, expressed as dimensionless fractions; (g) where emission factors for fuels are related to mass or volume instead of energy, values determined pursuant to Article 26(5) for the net calorific value of the respective source stream; (h) where a source stream is a type of waste, the relevant waste codes pursuant to Commission Decision 2014/955/EU (18);
(7) Where a mass balance methodology is applied, the mass flow, and carbon content for each source stream into and out of the installation; biomass fraction, zero-rated biomass fraction, RFNBO or RCF fraction, zero-rated RFNBO or RCF fraction, synthetic low-carbon fraction, zero-rated synthetic low-carbon fraction, and net calorific value, where relevant;
(8) Information to be reported as memo items, consisting of at least: (a) amounts of biomass and of zero-rated biomass combusted or amounts of RFNBO or RCF and of zero-rated RFNBO or RCF combusted, or amounts of synthetic low-carbon fuels and of zero-rated synthetic low-carbon fuels combusted, expressed in TJ, or employed in processes, expressed in t or Nm3; (b) CO2 emissions from biomass and from zero-rated biomass or emissions from RFNBO or RCF and from zero-rated RFNBO or RCF, or emissions from synthetic low-carbon fuels and of zero-rated synthetic low-carbon fuels expressed in t CO2, where measurement-based methodology is used to determine emissions; (c) a proxy for the net calorific value of the biomass or RFNBO or RCF or synthetic low-carbon fuels source streams used as fuel, where relevant; (d) emissions, amounts and energy content of biomass fuels and bioliquids combusted or RFNBO or RCF combusted, or synthetic low-carbon fuels combusted expressed in t and TJ, and information that zero-rated biomass fuels and bioliquids or RFNBO or RCF or synthetic low-carbon fuels comply with Article 38(5) or Article 39a(3) or Article 39a(4) of this Regulation; (e) CO2 or N2O transferred to an installation or received from an installation and any CO2 in transit, where Article 49 or 50 of this Regulation is applicable, expressed in t CO2(e); (f) inherent CO2 transferred to an installation or received from an installation, where Article 48 is applicable, expressed in t CO2; (g) where applicable, the name of the installation and its identification code as recognised in accordance with the acts adopted pursuant to Article 19(3) of Directive 2003/87/EC: (i) of the installation(s) to which CO2 or N2O is transferred in accordance with points (e) and (f) of this point (8); (ii) of the installation(s) from which CO2 or N2O is received in accordance with points (e) and (f) of this point (8); Where that installation does not have such identification code, the name and address of the installation as well as relevant contact information of a contact person shall be provided. (h) transferred CO2 from biomass, expressed in t CO2; (i) amount of CO2 chemically bound in product in accordance with Article 49a(1) of this Regulation, expressed in t CO2; (j) the types and amounts of products produced in which CO2 was chemically bound in accordance with Article 49a(1) of this Regulation, expressed in t of product.
(9) Where a measurement methodology is applied: (a) where CO2 is measured as the annual fossil CO2-emissions and the annual CO2-emissions from biomass use; (b) the hours of operation of the continuous emission measurement system (CEMS), the measured greenhouse gas concentrations and the flue gas flow expressed as an annual hourly average, and as an annual total value; (c) where applicable, a proxy for the energy content from fossil fuels and materials and from biomass used as fuels and materials as well as from RFNBO or RCF or synthetic low-carbon fuels.
(10) Where a methodology referred to in Article 22 is applied, all data necessary for determining the emissions for the emission sources and source streams for which that methodology is applied, as well as proxy data for activity data, calculation factors and other parameters which would be reported under a tier methodology;
(11) Where data gaps have occurred and have been closed by surrogate data in accordance with Article 66(1): (a) the source stream or emission source to which each data gap applies; (b) the reasons for each data gap; (c) the starting and ending date and time of each data gap; (d) the emissions calculated based on surrogate data; (e) where the estimation method for surrogate data has not yet been included in the monitoring plan, a detailed description of the estimation method including evidence that the methodology used does not lead to an underestimation of emissions for the respective time period;
(12) Any other changes in the installation during the reporting period with relevance for that installation's greenhouse gas emissions during the reporting year;
(13) Where applicable, the production level of primary aluminium, the frequency and average duration of anode effects during the reporting period, or the anode effect overvoltage data during the reporting period, as well as the results of the most recent determination of the installation-specific emission factors for CF4 and C2F6 as outlined in Annex IV, and of the most recent determination of the collection efficiency of the ducts.
Emissions occurring from different emission sources, or source streams of the same type of a single installation belonging to the same type of activity may be reported in an aggregate manner for the type of activity.
Where tiers have been changed within a reporting period, the operator shall calculate and report emission as separate sections of the annual report for the respective parts of the reporting period.
Operators of CO2 storage sites may use simplified emission reports after closure of the storage site in accordance with Article 17 of Directive 2009/31/EC containing at least the elements listed under points 1 to 5, provided the greenhouse gas emissions permit contains no emission sources.
2. ANNUAL EMISSION REPORTS OF AIRCRAFT OPERATORS
The emission report for an aircraft operator shall at least contain the following information:
(1) Data identifying the aircraft operator as set out by Annex IV to Directive 2003/87/EC, and the call sign or other unique designators used for air traffic control purposes, as well as relevant contact details;
(2) Name and address of the verifier of the report;
(3) The reporting year;
(4) Reference to and version number of the latest approved monitoring plan and the date from which it is applicable, reference to and version number of other monitoring plans relevant for the reporting year;
(5) Relevant changes in the operations and deviations from the approved monitoring plan during the reporting period;
(6) The aircraft registration numbers and types of aircraft used in the period covered by the report to perform the aviation activities covered by Annex I to Directive 2003/87/EC carried out by the aircraft operator;
(7) The total number of flights per State pair covered by the report;
(8) Mass of neat fuel (in tonnes) per fuel type per State pair, including information on all of the following: (a) Whether the alternative aviation fuel is zero-rated in compliance with Article 54c of this Regulation; (b) Whether the fuel is an eligible aviation fuel; (c) For eligible aviation fuels, the fuel type as defined in Article 3c(6) of Directive 2003/87/EC;
(9) Total CO2 emissions in tonnes of CO2 using the preliminary emission factor as well as the emission factor disaggregated by the Member State of departure and arrival;
(10) Where emissions are calculated using an emission factor or carbon content related to mass or volume, proxy data for the net calorific value of the fuel;
(11) Where data gaps have occurred and have been closed by surrogate data in accordance with Article 66(2): (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; (b) the estimation method for surrogate data applied; (c) the emissions calculated based on surrogate data;
(12) Memo-items: (a) amount of alternative aviation fuels used during the reporting year (in tonnes) listed per fuel type, and whether the fuels comply with Article 54c of this Regulation; (b) the net calorific value of alternative fuels;
(12a) Total amount of eligible aviation fuels used during the reporting year (in tonnes) listed per fuel type as per Article 3c(6) of Directive 2003/87/EC;
(13) As an annex to the annual emission report, the aircraft operator shall include annual emissions and annual numbers of flights per aerodrome pair. If applicable, the amount of alternative aviation fuel and eligible aviation fuel (in tonnes) shall be indicated per aerodrome pair. Upon request of the operator the competent authority shall treat that information as confidential.
2a. ANNUAL NON-CO2 AVIATION EFECTS REPORTS OF AIRCRAFT OPERATORS
For non-CO2 aviation effects, the separate report as referred to in Article 68(5) of this Regulation shall at least contain the following information:
(1) Data identifying the aircraft operator, and the call sign or other unique designators used for air traffic control purposes, as well as relevant contact details;
(2) Name and address of the verifier of the report;
(3) The reporting year;
(4) Reference to and version number of the latest approved monitoring plan and the date from which it is applicable, reference to and version number of other monitoring plans relevant for the reporting year;
(5) Relevant changes in the operations and deviations from the approved monitoring plan during the reporting period;
(6) The aircraft registration numbers and types of aircraft used in the period covered by the report to perform the aviation activities covered by Annex I to Directive 2003/87/EC carried out by the aircraft operator;
(7) The total number of flights per State pair covered by the report;
(8) The sum of CO2(e) of the monitored flights of the aircraft operator per aerodrome pair, expressed in the climate metrics provided in Article 56a(2) of this Regulation.
(9) A XML table containing per flight and as defined in Annex IIIa, Section 1 to this Regulation, flight information, aircraft type, engine identifier and CO2(e), expressed in the climate metrics provided in Article 56a(2) of this Regulation;
(10) If the aircraft operator is not using NEATS to calculate the CO2(e), but own or third-party IT tools as referred to in Article 56a(7)(b) of this Regulation, a description of how efficacy is applied in those tools, in line with this Regulation and NEATS, to refine the GWP. If efficacy was not applied in the tools, the aircraft operator shall provide a description explaining the reasons for not applying efficacy.
4. ANNUAL EMISSION REPORTS OF REGULATED ENTITIES
The annual emission report of a regulated entity shall at least contain the following information:
(1) Data identifying the regulated entity, as specified in Annex IV to Directive 2003/87/EC, and its unique greenhouse gas permit number;
(2) Name and address of the verifier of the report;
(3) The reporting year;
(4) Reference to and version number of the latest approved monitoring plan and the date from which it is applicable, as well as reference to and version number of any other monitoring plans relevant for the reporting year;
(5) Relevant changes in the operations of the regulated entity and changes as well as temporary deviations that occurred during the reporting period to the monitoring plan approved by the competent authority; including temporal or permanent changes of tiers, reasons for those changes, starting date for the changes, and starting and ending dates of temporal changes;
(6) Information for all fuel streams consisting of at least: (a) the total emissions expressed as t CO2, including CO2 from biomass fuel streams which do not comply with Article 38(5) of this Regulation, or from RFNBO or RCF source streams which do not comply with Article 39a(3) of this Regulation, or from synthetic low-carbon fuels source streams which do not comply with Article 39a(4) of this Regulation; (b) the tiers applied; (c) released fuel amounts, (expressed as tonnes, Nm3 or TJ,) and the unit conversion factor, expressed in appropriate units, reported separately, where applicable; (d) emission factors, expressed in accordance with the requirements set out in Article 75f of this Regulation; biomass fraction, zero-rated biomass fraction, RFNBO or RCF fraction, zero-rated RFNBO or RCF fraction, synthetic low-carbon fraction, zero-rated synthetic low-carbon fraction expressed as dimensionless fractions; (e) where emission factors for fuels are related to mass or volume instead of energy, values determined pursuant to Article 75h(3) for the unit conversion factor of the respective fuel stream; (f) the means through which the fuel is released for consumption; (g) the end use(s) of the fuel stream released for consumption including the CRF code, at the level of detail available; (h) the scope factor, expressed as dimensionless fraction, up to three decimal points. Where, for a fuel stream, more than one method is used to determine the scope factor, the information on the type of method, the associated scope factor, the released fuel amount and the CRF code at the level of detail available; (i) where the scope factor is zero pursuant to Article 75l(1): (i) A list of all entities covered by Chapters II and III of Directive 2003/87/EC identified by their name, address and, where applicable, unique permit number; (ii) The released fuel amounts supplied to each entity covered by Chapters II and III of Directive 2003/87/EC for the relevant reporting period, expressed as t, Nm3, or TJ, as well as the corresponding emissions.
(7) Information to be reported as memo items, consisting of at least: (a) a proxy for the net calorific value of the biomass, RFNBO or RCF or synthetic low-carbon fuels fuel streams, where relevant; (b) emissions, amounts and energy content of biofuels, bioliquids, biomass fuels, RFNBOs and RCFs, synthetic low-carbon fuels released for consumption, expressed in t and TJ, and information whether they comply with Article 38(5) or 39a(3) or 39a(4) of this Regulation;
(8) Where data gaps have occurred and have been closed by surrogate data in accordance with Article 66(1): (a) the fuel stream to which each data gap applies; (b) the reasons for each data gap; (c) the starting and ending date and time of each data gap; (d) the emissions calculated based on surrogate data; (e) where the estimation method for surrogate data has not yet been included in the monitoring plan, a detailed description of the estimation method including evidence that the methodology used does not lead to an underestimation of emissions for the respective time period;
(9) Any other changes in the regulated entity during the reporting period with relevance for that regulated entity’s greenhouse gas emissions during the reporting year.
ANNEX Xa
Together with the information contained in the annual emission report pursuant to Annex X to this Regulation, the operator shall submit the following information for each purchased fuel as defined in Article 3, point (af) of Directive 2003/87/EC:
(a) name, address and unique permit number of the fuel supplier which is registered as regulated entity. In cases where the fuel supplier is not a regulated entity, the operators shall submit, where available, a list of all suppliers of fuels, from direct fuel suppliers up to the regulated entity, including their name, address and unique permit number;
(b) the types and amounts of fuels acquired from each supplier referred to in point (a) during the relevant reporting period;
(c) the amount of fuel used for activities referred to in Annex I to Directive 2003/87/EC from each fuel supplier during the relevant reporting period.
ANNEX Xb
Together with the information contained in the annual emission report pursuant to Annex X to this Regulation, the regulated entity shall submit the following information for each purchased fuel as defined in Article 3, point (af), of Directive 2003/87/EC:
(a) name, address and unique permit number of the operator and, where relevant, the aircraft operator and shipping company, to whom the fuel is released. In other cases where the fuel is meant for end use in sectors covered by Annex I to Directive 2003/87/EC the regulated entity shall submit, where available, a list of all consumers of fuels, from direct buyer down to the operator, including their name, address and unique permit number, where this would not cause disproportionate administrative burden;
(b) the types and amounts of fuels sold to each buyer referred to in point (a) during the relevant reporting period.
(c) the amount of fuel used for activities referred to in Annex I to Directive 2003/87/EC for each buyer referred to in point (a) during the relevant reporting period..
ANNEX XI
Correlation table
| Commission Regulation (EU) No 601/2012 | This Regulation |
|---|---|
| Article 1 to 49 | Article 1 to 49 |
| — | Article 50 |
| Article 50 to 67 | Article 51 to 68 |
| Article 68 | — |
| Article 69 to 75 | Article 69 to 75 |
| — | Article 76 |
| Article 76 to 77 | Article 77 to 78 |
| Annex I to X | Annex I to X |
| — | Annex XI |
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