CRCF Bio-CCS v1.0 — Isometric

1.0

Summary

This Protocol provides the requirements and procedures for the calculation of net CO₂ equivalent (CO₂e) removals from the atmosphere via Industrial Process Biogenic Carbon Capture and Storage (Bio-CCS). This Protocol is developed for issuing Credits under the EU Carbon Removal and Carbon Farming (CRCF) framework established by EU Regulation 2024/3012.

This Protocol contains all relevant requirements laid out in the Delegated Act Annex, and a series of Modules which each apply the relevant additional Isometric requirements to ensure all Isometric CRCF Projects have the same quality assurance, durability and scientific rigour as comparable non-CRCF Isometric Projects.

Under this protocol, Isometric additional modules can only ever institute additional checks or subtract from the CRCF equation terms, and never result in a higher credit total.

The only place where the Delegated Act Annex text has been modified is (with Isometric additions in bold):

section 6: Isometric CRCF Requirements has been added to apply the Isometric CRCF Modules.

Isometric CRCF Protocols use CRCF terminology defined by the CRCF Regulations. These terms are considered equivalent to Isometric terminology according to this glossary.

2.0

Description of the Carbon Removal Activity

2.1

Eligibility

2.1.1

Carbon Removal Activities With CO|2| Capture and Geological Storage

Carbon Removal Activities With CO₂ Capture and Geological Storage

Only the capture facilities may be Operators of Bio-CCS activities.

BioCCS activities may transfer all or part of the captured CO2 to storage sites for permanent storage to generate permanent carbon removal units. If part of the captured CO2 is transferred for utilisation or is transferred for storage but recognised under an alternative framework, no permanent carbon removal units will be generated in respect of that fraction of the CO₂.

The biogenic CO₂ captured in a BioCCS Activity shall be generated as a by-product of production processes of goods, energy and services and shall not generate biogenic CO₂ from biomass, biofuel, bioliquid or biomass fuel solely for the purpose of capture and storage.

The Operator of a BioCCS activity shall ensure that the facility capturing the CO₂ is located in the Union.

2.2

Activity Period|, Monitoring Period and |Certification Period

Activity Period, Monitoring Period and Certification Period

2.2.1

Bio-CCS Activities

2.2.1.1

Activity Period

The duration of any Activity Period for Bio-CCS activities shall not exceed 15 years. At the end of every Activity Period Operators may start a new Activity Period by submitting a new Activity Plan.

2.2.1.2

Monitoring Period

The Monitoring Period for Bio-CCS activities shall be the period up until the point at which responsibility for all geological storage sites utilised by the Activity has been transferred to the relevant competent national authorities in accordance with Article 18 of Directive 2009/31/EC of the European Parliament and of the Council.

Article 18 of Directive 2009/31/EC

where a storage site has been closed pursuant to points (a) or (b) of Article 17(1), responsibility must be transferred to the competent authority on its own initiative or upon request from the Project Proponent, if the following conditions are met:
all available evidence indicates that the stored CO₂ will be completely and permanently contained;
a minimum period, to be determined by the competent authority, has elapsed. This minimum period must be no shorter than 20 years, unless the competent authority is convinced that the criterion referred to in point (a) is complied with before the end of that period;
the financial obligations referred to in Article 20 have been fulfilled;
the site has been sealed and the injection facilities have been removed.
the Project Proponent must prepare a report documenting that the condition referred to in paragraph 1(a) has been met and must submit it to the competent authority for the latter to approve the transfer of responsibility. This report must demonstrate, at least:
the conformity of the actual behaviour of the injected CO₂ with the modelled behaviour;
the absence of any detectable leakage;
that the storage site is evolving towards a situation of long-term stability.

The Commission may adopt guidelines on the assessment of the matters referred to in points (a), (b) and (c) of the first subparagraph, highlighting therein any implications for the technical criteria relevant to the determination of the minimum periods referred to in paragraph 1(b); 3. where the competent authority is satisfied that the conditions referred to in points (a) and (b) of paragraph 1 are met, it must prepare a draft decision of approval of the transfer of responsibility. The draft decision must specify the method for determining that the conditions referred to in paragraph 1(d) have been met as well as any updated requirements for the sealing of the storage site and for the removal of injection facilities. If the competent authority considers that the conditions referred to in points (a) and (b) of paragraph 1 are not met, it must inform the Project Proponent of its reasons; 4. member States must make the reports referred to in paragraph 2 available to the Commission within one month after receipt. They must also make available other related material that will be taken into account by the competent authority when it prepares a draft decision of approval on the transfer of responsibility. They must inform the Commission of all draft decisions of approval prepared by the competent authority pursuant to paragraph 3, including any other material taken into consideration for arriving at its conclusion. Within four months after receipt of the draft decision of approval, the Commission may issue a non-binding opinion on it. If the Commission decides not to issue an opinion, it must inform the Member State within one month of submission of the draft decision of approval and state its reasons; 5. where the competent authority is satisfied that the conditions referred to in points (a) to (d) of paragraph 1 are complied with, it must adopt the final decision and notify that decision to the Project Proponent. The competent authority must also notify the final decision to the Commission, and where it departs from the Commission opinion it must state its reasons; 6. after the transfer of responsibility, routine inspections provided for in Article 15(3) must cease and monitoring may be reduced to a level which allows for detection of leakages or significant irregularities. If any leakages or significant irregularities are detected, monitoring must be intensified as required to assess the scale of the problem and the effectiveness of corrective measures; 7. in cases where there has been fault on the part of the Project Proponent, including cases of deficient data, concealment of relevant information, negligence, wilful deceit or a failure to exercise due diligence, the competent authority must recover from the former Project Proponent the costs incurred after the transfer of responsibility has taken place. Without prejudice to Article 20, there must be no further recovery of costs after the transfer of responsibility; 8. where a storage site has been closed pursuant to Article 17(1)(c), transfer of responsibility will be deemed to take place if and when all available evidence indicates that the stored CO₂ will be completely and permanently contained, and after the site has been sealed and the injection facilities have been removed.

2.2.1.3

Certification Period

The duration of the Certification Period for Bio-CCS activities shall not exceed 1 year.

Where it is not possible to precisely identify the period in time during which CO₂ captured during a given Certification Period physically enters permanent storage, Operators may estimate emissions associated with transport and storage based on data recorded during the Certification Period without including in the calculation a temporal delay between the time at which the CO₂ was captured and the time at which it is injected, by assessing the average associated emissions (including fugitive emissions, leaks or venting) during transport and storage of CO₂, per tonne of CO₂ handled during the Certification Period.

2.3

Planning and Reporting

2.3.1

Activity Plan

Before the certification audit, the Operator shall submit to the Certification Body an Activity Plan that includes the information necessary to assess compliance with the requirements of this methodology, as referred to in the third paragraph. Where an Operator wishes to change the Activity Plan during the Activity Period, that Operator shall submit a rationale behind the changes to the Certification Bodies without delay and shall include any adjustment to the initial plan, in particular the recalculation of the expected greenhouse gas (‘GHG’) emissions and removals and impacts on sustainability requirements.

The activity plan shall include:

a general description of the Activity, the technologies and the infrastructure to be utilised;
details of all entities of the carbon removal value chain involved in delivery of the activity;
identification and demonstration of compliance of the Activity with any relevant local, regional and national laws, statutes and regulatory frameworks;
a list of emissions sources and sinks that are relevant to the Activity, in accordance with Section 3.1.1;
estimates of total carbon removals and GHG associated emissions of the Activity for the Activity Period, in accordance with points (k), (l) and (m) of Annex II to Regulation (EU) 2024/3012 of the European Parliament and of the Council;
a description of any materiality assessment undertaken in accordance with Section 3.3.1;
a description of the assessment of uncertainty, in accordance with Section 3.3.6;
proof of compliance with the minimum sustainability requirements, in accordance with Section 5.1;
funding sources received or applied for with regard to the activity, in accordance with Sections 3.1.2;
any other information necessary for the certification body to conduct the certification audit in accordance with Article 9 of Regulation (EU) 2024/3012.

2.3.2

Monitoring Plan

Before the Certification Audit, Operators shall submit a Monitoring Plan to the Certification Body. That Monitoring Plan shall comply with the following criteria:

it shall include description of the activity to be monitored;
it shall include a description of the procedure for managing the assignment of responsibilities for monitoring and reporting, and for managing the competences of relevant personnel;
it shall include, 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;
it shall include, where applicable, a list of laboratories engaged in carrying out relevant analytical procedures;
it shall include, where measurements are taken, a description of the measurements method including descriptions of all written procedures relevant for the measurement;
it shall include, where applicable, a detailed description of the monitoring methodology where transfer of CO₂ is carried out, including a description of continuous measurement systems used and of procedures for preventing, detecting and quantification of leakage events from CO₂ transport infrastructure;
it shall apply, where applicable, the minimum frequencies for analysis listed in Annex VII to Commission Implementing Regulation (EU) 2018/2066;
it shall apply the standard for quality assurance laid down in Article 60 of Implementing Regulation (EU) 2018/2066;
it shall include a record keeping requirement for all relevant data and information consistent with the record keeping requirements laid down in Article 67(1) of Implementing Regulation (EU) 2018/2066.

In the case that it is not possible to fully detail the monitoring plan when an operator applies for certification, the monitoring plan shall be submitted as completely as possible, clearly indicating any non-final aspects and providing an indication of how the operator expects these aspects to be addressed. The activity may be certified on this basis provided the certification body accepts that the omissions are properly justified. The monitoring plan shall be finalised and presented to the certification body prior to the first re-certification.

Operators shall obtain, record, compile, analyse and document monitoring data, including assumptions, references, Activity data and calculation factors in a transparent manner that enables the checking of performance achieved during the various Activity stages, and, when requested, report this information to the Certification Body or Isometric.

Each parameter monitored shall be accompanied with the following information:

the entity responsible for collection and archiving;
the data source;
the equipment, measurement methods and procedures used for monitoring, including details on accuracy and calibration;
the monitoring frequency;
the quality assessment and quality check procedures.

All measurements shall be conducted with calibrated measurement equipment according to industry standards, following the requirements in Articles 42 of Implementing Regulation (EU) 2018/2066, and any necessary data aggregation shall be undertaken following the requirements in Article 44 of that Implementing Regulation (EU) 2018/2066.

Annex VII to Commission Implementing Regulation (EU) 2018/2066 Full Article 35

the Project Proponent must apply the minimum frequencies for analyses for relevant fuels and materials listed in Annex VII;
the competent authority may allow the Project Proponent to use a frequency that differs from those referred to in paragraph 1, where minimum frequencies are not available or where the Project Proponent 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 Project Proponent has to adhere with regard to the activity data determination of the relevant fuel or material;
where an installation operates for part of the year only, or where fuels or materials are delivered in batches that are consumed over more than one calendar year, the competent authority may agree with the Project Proponent a more appropriate schedule for analysis.

Minimum frequency of analyses (Article 35)

Minimum frequency of analyses

Fuel/material	Minimum frequency of analyses
Natural gas	At least weekly
Other gases, in particular synthesis gas and process gases such as refinery mixed gas, coke oven gas, blast-furnace gas, 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

Article 22

Article 22 Monitoring methodology not based on tiersBy way of derogation from Article 21(1), the Project Proponent 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:1. 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; 2. the Project Proponent 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; 3. the Project Proponent 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 44

Article 44 Data aggregation1. the Project Proponent must calculate hourly averages for each parameter, including concentrations and flue gas flow, relevant for determining emissions using a measurement-based methodology by using all data points available for that specific hour. Where a Project Proponent can generate data for shorter reference periods without additional cost, the Project Proponent must use those periods for the determination of the annual emissions in accordance with Article 43(1); 2. where the continuous measurement equipment for a parameter is out of control, out of range or out of operation for part of the hour or reference period referred to in paragraph 1, the Project Proponent must calculate the related hourly average pro rata to the remaining data points for that specific hour or shorter reference period, provided that at least 80 % of the maximum number of data points for a parameter are available.Article 45(2) to (4) must apply where fewer than 80% of the maximum number of data points for a parameter are available.

2.3.3

Monitoring Report

Before each Re-Certification Audit, the Operator shall submit to the Certification Body a monitoring report including the net carbon removal benefit, the total amount of gross carbon removal generated by the Activity, the amount of greenhouse gases associated to the Activity and all necessary information relating to the quantification of the net carbon removal benefit and any relevant information on the compliance of the Activity with storage, liability and sustainability requirements. In particular, the monitoring report shall include the following:

all the parameters specified in Sections 3.1.5.4, 3.1.6.3 and 3.1.7.5, measured and calculated for the quantification of carbon removals and GHG emissions associated with the Activity. All removals and emissions of CO₂ and emissions of other GHGs shall be assessed over the Certification Period that is to be audited and reported in the monitoring report. Emissions of GHGs other than CO₂ shall be converted to tonnes of CO₂e by use of the 100-year Global Warming Potentials set out in Annex I to Commission Delegated Regulation (EU) 2020/1044;
the biomass feedstock or feedstock mix consumed as required under Section 4.2 (a)(ii);
the quantity of carbon farming sequestration units that have been purchased in accordance with Section 4.3.3;
financing received or applied for with regard to the Activity, in accordance with Section 3.1.2.

Annex I to Commission Delegated Regulation (EU) 2020/1044 Global Warming Potential

Acronym, common name or chemical name	Global warming potential
Carbon dioxide (CO₂)	1
Methane (CH₄)	28
Nitrous oxide (N₂O)	265
Sulphur hexafluoride (SF₆)	23 500
Nitrogen trifluoride (NF₃)	16 100

3.0

Quantification of Baseline, Total Carbon Removal and Associated GHG Emissions

3.1

Bio-CCS Activities

3.1.1

GHG Sources and Sinks

Bio-CCS activities shall consider the GHG sources and sinks included in Table 1.

Table 1: Sinks and sources that shall be included for Bio-CCS activities.

Phase of the Activity	Emission sources and sinks	Gases included
CO₂ capture	Capture facility: Operation of equipment used to capture CO₂ from biogenic emissions, including equipment used to generate airflow, and equipment associated with regeneration processes to recover the fluids or other media used in the carbon capture process.	All GHGs
	Capture facility: Any CO₂ conditioning equipment used to further process the CO₂ stream before transfer to transport or storage infrastructure.	All GHGs
	Capture facility: Any associated energy generation equipment powering the capture process that is under the control of the Operator of the capture facility.	All GHGs
	Capture facility: Any treatment equipment for processing wastes or byproducts of the carbon capture process.	All GHGs
	Capture facility: Fuel combustion, electricity consumption, heat consumption.	All GHGs
	Biomass supply: Emissions associated with additional biomass, biofuels, bioliquids and biomass fuels consumed for the operation of the capture facility (e.g., emissions for the harvest or transport of biomass).	All GHGs
	Input emissions: Production and supply of inputs used by the capture facility.	All GHGs
	Waste treatment: Processing and treatment of any wastes (including wastewater and exhaust gases) generated by the capture facility.	All GHGs
	Capital emissions: The emissions associated with the construction and installation of the capture facility.	All GHGs
Transport of CO₂	Transportation: Fuel consumption and electricity consumption of road and rail transportation, maritime transportation and other vehicles.	All GHGs
	Infrastructure: Fuel consumption, electricity consumption and heat consumption in infrastructure and buildings functionally connected to the pipeline transport network (e.g. booster/compressor stations, heaters, CO₂ hubs, intermediate storage).	All GHGs
	Losses: CO₂ fugitive, vented, and leakage emissions from the transport network.	CO₂ only
Injection at the geological storage site	Storage site: Removal by CO₂ injection.	CO₂ only
	Storage site: Fuel consumption, electricity consumption, heat consumption.	All GHGs
	Losses: CO₂ fugitive and vented emissions from injection and from the storage site prior to entering permanent geological storage.	CO₂ only
	Input emissions: Production and supply of any inputs used by the storage site.	All GHGs
	Waste treatment: Processing and treatment of any wastes (including wastewater and exhaust gases) generated by the storage site.	All GHGs
	Capital emissions: The emissions associated with the construction and installation of the storage site.	All GHGs

3.1.2

Baseline

A standardised baseline set to 0 tonnes of CO₂ per year (tCO₂/year) shall apply for Bio-CCS activities.

Where the Activity is financed through a combination of public and private funding when submitting the Activity Plan to Isometric, Operators shall indicate any form of public financing received or applied for with regard to the Activity. This information shall be included in the certificate of compliance.

3.1.3

Quantification of the Total Removals of the Activity

Operators may use one of two approaches for the calculation of the total carbon removal ( $CR_{total}$ ), either the approach specified in Section 3.1.3.3 or that in Section 3.1.3.4, depending on whether the CO₂ captured by the Activity would be kept fully segregated from CO₂ from other sources through the transport infrastructure and at the storage site.

3.1.3.1

Identification of Captured CO|2| Streams

Identification of Captured CO₂ Streams

A capture facility may capture CO₂ that is:

solely biogenic CO₂;
a combination of biogenic CO₂ and fossil CO₂ from a mixed CO₂ stream;
fossil CO₂ captured from a process associated with the capture process.

The fractions of CO₂ captured by the Activity shall be given the following designations. The total amount of CO₂ captured at the capture facility and transferred for transport or storage shall be designated $CO_{2\ captured,total}$ and calculated in accordance with Equation 1.

 $CO_{2\ captured,total} = \sum_i CO_{2\ OUT,activity,i}$

(Equation 1)

Where:

$CO_{2\ OUT,activity,i}$ = minus the amount of CO₂ from the capture Activity leaving the capture facility at each exit point i, which shall be measured.

Any leakage of CO₂ occurring between the point of capture and the point of leaving the capture facility is implicitly excluded from the term $CO_{2\ captured,total}$ .

The amount of biogenic CO₂ that is captured at the capture facility and is transferred for transport or storage shall be designated $CO_{2\ captured,atmobio}$ and shall be calculated in accordance with Equation 2.

 $CO_{2\ captured,atmobio} = CO_{2\ captured,total} - CO_{2\ captured,fossil}$

(Equation 2)

Where:

$CO_{2\ captured,total}$ = defined in Equation 1;
$CO_{2\ captured,fossil}$ = defined in Equation 3.

In some Activities, fossil CO₂ will be captured alongside CO₂ of biogenic origin. Where fossil CO₂ is emitted as a result of the capture process, it may be captured, either separately from the capture of CO₂ of biogenic origin ("separate capture") or simultaneously with the capture of CO₂ of biogenic origin ("co-capture"). If it is then permanently stored it may be excluded from the calculation of $GHG_{associated}$ . For Bio-CCS activities only it is also permissible to capture CO₂ from a mixed stream consisting of a combination of biogenic CO₂ and fossil CO₂. Fossil CO₂ captured from the capture process is associated with the Activity, and emissions from transporting and storing that CO₂ shall be included in $GHG_{associated}$ . Fossil CO₂ captured from a mixed stream by a Bio-CCS Activity is not associated with the Activity, and emissions from transporting and storing that CO₂ shall not be included in $GHG_{associated}$ . The amount of fossil CO₂ that is captured at the capture facility shall be calculated in accordance with Equation 3.

 $CO_{2\ captured,fossil} = CO_{2\ captured,fossil} + CO_{2\ captured,fossil,mixed}$

(Equation 3)

Where:

$CO_{2\ captured,fossil,assoc}$ = minus the amount of fossil CO₂ emitted as a result of the capture process that is captured, calculated using Equation 4;
$CO_{2\ captured,fossil,mixed}$ = minus the amount of fossil CO₂ captured from a mixed stream as part of a Bio-CCS Activity, calculated using Equation 5.

The amount of CO₂ emitted as a result of the capture process that is captured, $CO_{2\ captured,fossil,assoc}$ , shall be determined in accordance with Equation 4 as the sum of the separately captured and co-captured components.

 $CO_{2\ captured,fossil,assoc} = CO_{2\ fossil,assoc,co-captured} + \sum_{sources} CO_{2\ fossil,assoc,source}$

(Equation 4)

Where:

$CO_{2\ fossil,assoc,co-captured}$ = minus the amount of CO₂ emitted as a result of the capture process that is co-captured with the biogenic CO₂. The Certification Body shall confirm this amount is not more than the fossil CO₂ emissions at the capture facility reported in the calculation of $GHG_{associated}$ ;
$CO_{2\ fossil,assoc,source}$ = minus the measured amount of CO₂ from a source emitted as a result of the capture process that is captured separately from the capture of CO₂ of biogenic origin;
$sources$ = an index of the point sources from which fossil CO₂ from processes associated with the Activity is separately captured.

The amount of fossil CO₂ that is captured from a mixed stream as part of a Bio-CCS Activity shall be calculated in accordance with Equation 5.

 $CO_{2\ captured,fossil,mixed} = 1-F_B \cdot (CO_{2\ captured,total} - CO_{2\ captured,fossil,assoc})$

(Equation 5)

Where:

$F_B$ = the fraction of capture CO₂ from a mixed stream that is of biogenic origin. This shall be calculated in accordance with Article 39 of Implementing Regulation (EU) 2018/2066. See Section 3.1.5.2;
$CO_{2\ captured,total}$ = is defined in Equation 1;
$CO_{2\ captured,fossil,assoc}$ = is defined in Equation 4.

Article 39 of Implementing Regulation (EU) 2018/2066

Determination of biomass and fossil fraction1. for mixed fuels or materials, the Project Proponent may either assume the absence of biomass and apply a default fossil fraction of 100 %, or determine a biomass fraction in accordance with paragraph 2, applying tiers as defined in section 2.4 of Annex II.- where, subject to the tier level required, the Project Proponent has to carry out analyses to determine the biomass fraction, it must do so on the basis of a relevant standard and the analytical methods therein, provided that the use of that standard and analytical method are approved by the competent authority. Where, subject to the tier level required, the Project Proponent 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 Project Proponent must 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 Project Proponent 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.- by way of derogation from paragraphs 1 and 2 and Article 30, where the guarantee of origin has been established in accordance with Articles 2(j) and 15 of Directive 2009/28/EC for biogas injected into and subsequently removed from a gas network, the Project Proponent must not use analyses to determine the biomass fraction.

The amount of captured CO₂ for which transport or storage emissions shall be counted towards the term $GHG_{associated}$ shall be designated $CO_{2\ activity}$ and shall be calculated in accordance with Equation 6 as the sum of the biogenic CO₂ captured by the Activity and transferred for permanent storage to be counted towards total carbon removals and the associated share of the amount of fossil CO₂ captured at the capture facility from processes that are specifically associated with the Activity.

 $CO_{2\ activity} = F_{CRCF} \cdot (CO_{2\ captured,atmobio} + CO_{2\ captured,fossil,assoc})$

(Equation 6)

Where:

$F_{CRCF}$ = defined in Section 3.1.3.2;
$CO_{2\ captured,atmobio}$ = defined in Equation 2;
$CO_{2\ captured,fossil,assoc}$ = defined in Equation 4.

3.1.3.2

Fraction of Captured CO|2| to Be Counted Towards the Total Carbon Removal

Fraction of Captured CO₂ to Be Counted Towards the Total Carbon Removal

An Operator may choose to dispatch some fraction of the captured CO₂ of biogenic origin for purposes other than storage at an eligible site, or may choose to count part of the CO₂ that is permanently stored under a scheme other than the Regulation (EU) 2024/3012. The Operator shall designate the fraction of the captured CO₂ of biogenic origin that will be counted towards the total carbon removal as $F_{CRCF}$ , which shall be 1 in the case that all of the captured CO₂ of biogenic origin will be transferred to permanent storage and generate permanent carbon removal units.

3.1.3.3

Segregated CO|2| Stream

Segregated CO₂ Stream

If the $CO_{2\ captured,total}$ is sent for storage and this CO₂ is at all times segregated from CO₂ from other sources during transit in the transport infrastructure and during storage and injection at the storage sites, $CR_{total}$ shall be measured as the quantity of CO₂ entering storage, adjusted where necessary to exclude any CO₂ in the segregated stream that is not biogenic in accordance with Equation 7.

 $CR_{total} = F_C \cdot F_{CRCF} \cdot \left(\frac{CO_{2\ captured,atmobio}}{CO_{2\ captured,total}} \cdot \sum_{S}(CO_{2\ injected,S})\right)$

(Equation 7)

Where:

$CO_{2\ injected,S}$ = minus the amount of CO₂ (of all origins) from the segregated stream that is injected at each storage site S, which shall be measured during injection;
$CO_{2\ captured,atmobio}$ = defined in Equation 2;
$CO_{2\ captured,total}$ = defined in Equation 1;
$S$ = an index of utilised storage sites, at which CO₂ from the Activity is fully segregated from any CO₂ from other sources up to and including the point of injection;
$F_C$ = the conservatism factor calculated based on the uncertainty in the measurement of the Activity calculated in accordance with Section 3.2.6;
$F_{CRCF}$ = defined in Section 3.1.3.2.

3.1.3.4

Non-Segregated CO|2| Stream

Non-Segregated CO₂ Stream

As an alternative to Section 3.1.3.3, the Operator may or, where the CO₂ captured by the Activity is not fully segregated from other CO₂ in the transport infrastructure or at the storage site, shall calculate $CR_{total}$ in accordance with Equation 8.

 $CR_{total} = F_C \cdot (F_{CRCF} \cdot CO_{2\ captured,atmobio} + CO_{2\ transport,losses} + CO_{2\ storage,losses})$

(Equation 8)

Where:

$CO_{2\ captured,atmobio}$ = defined in Equation 2;
$CO_{2\ transport losses}$ = the amount of biogenic CO₂ lost during transport from the capture facility to the storage sites, calculated following the rules in Section 3.1.6.1;
$CO_{2\ storage losses}$ = the amount of biogenic CO₂ lost at the storage sites prior to entering permanent geological storage, calculated following the rules in Section 3.1.6.3;
$F_{CRCF}$ = defined in Section 3.1.3.2;
$F_C$ = the conservatism factor calculated based on the uncertainty in the measurement of the Activity calculated in accordance with Section 3.2.6.

3.1.4

Quantification of the Greenhouse Gas Emissions Associated With the Activity

The greenhouse gases associated shall be calculated according to Equation 9.

 $GHG_{associated} = F_{CRCF} \cdot GHG_{capture} + GHG_{transport} + GHG_{storage}$

(Equation 9)

Where:

$GHG_{capture}$ = the GHG emissions associated with the capture facility, calculated following the rules in Section 3.1.5.3 in the case of biogenic CO₂ capture;
$GHG_{transport}$ = the GHG emissions associated with CO₂ transport from the capture facility to the storage sites, calculated following the rules in Section 3.1.6.2;
$GHG_{storage}$ = the GHG emissions associated with the storage sites, calculated following the rules in Section 3.1.7.4;
$F_{CRCF}$ = is defined in Section 3.1.3.2.

3.1.5

Capture of CO|2| From Biogenic Emissions

Capture of CO₂ From Biogenic Emissions

3.1.5.1

Quantification of Total CO|2| Captured

Quantification of Total CO₂ Captured

The total amount of CO₂ captured at the capture facility, termed $CO_{2\ captured,total}$ , shall be calculated in accordance with Equation 1 and the quantity of CO₂ of biogenic origin captured, $CO_{2\ captured,atmobio}$ shall be calculated in accordance with Equation 2.

3.1.5.2

Capture of CO|2| From Partially Biogenic Streams

Capture of CO₂ From Partially Biogenic Streams

Activities that capture biogenic CO₂ as part of a mixed stream that also contains CO₂ of fossil or other origin may be certified for the biogenic part. Such activities include, among others, activities capturing CO₂ from co-fired bioenergy facilities or from waste-to-energy facilities processing partially biogenic waste, as well as from energy-intensive industries, including but not restricted to cement, lime, metal and silicon producers that use partially biogenic fuel or feedstock. Only the biogenic part of the captured CO₂ may be counted towards $CR_{total}$ . Emissions associated with the carbon capture facility shall be allocated proportionately between the biogenic fraction that shall be included in $CO_{2\ captured,atmobio}$ and the non-biogenic fraction that shall not be included in the quantification. After transfer of the CO₂ from the point of capture into transportation infrastructure or a storage site, either a segregated system or mass balance accounting shall be used to identify a quantity of biogenic CO₂ entering permanent storage that is consistent with the amount of biogenic CO₂ captured (minus any losses).

3.1.5.3

Quantification of Associated GHG Emissions

The calculation of the term $GHG_{capture}$ shall consider only the emissions specifically associated with operating the capture process and the transfer of the CO₂ for storage or transport. The calculation shall include emissions associated with any static and mobile machinery utilised to enable the capture process. Emissions associated with the normal operation of the facility generating the biogenic CO₂, that do not result from the operation of the capture process, shall not be included in the quantification. In the case that an emissions source (e.g., on-site mobile machinery) serves both the capture process and one or more other processes at the facility, then a pro-rata fraction of the emissions from that source shall be attributed to the capture process. $GHG_{capture}$ shall be calculated in accordance with Equation 17.

 $GHG_{capture} = \left(1- \frac{CO_{2\ captured,fossil,mixed}}{CO_{2\ captured,total}} \right) \cdot (GHG_{facility} + GHG_{inputs})$

(Equation 17)

Where:

$CO_{2\ captured,fossil,mixed}$ = defined in Equation 5;
$CO_{2\ captured,total}$ = defined in Equation 1;
$GHG_{facility}$ = the total GHG emissions from all relevant activities required for CO₂ capture at the capture facility, in tCO₂e, including emissions associated with conditioning the CO₂ prior to transfer to the transport infrastructure or storage site;
$GHG_{inputs}$ = the total emissions associated with inputs to the capture facility, in tCO₂e.

3.1.5.3.1

Emissions From the Capture Facility

The emissions $GHG_{facility}$ associated with the capture facility, shall be calculated in accordance with Equation 18.

 $GHG_{facility} = GHG_{bio} + GHG_{bio-storage} + GHG_{on-site} + GHG_{elec} + GHG_{heat} + GHG_{capital} + GHG_{disposal}$

(Equation 18)

Where:

$GHG_{bio}$ = the emissions due to the supply of additional biomass that is used to generate energy consumed by the capture process, calculated in accordance with Equation 19.

 $GHG_{bio} = \sum_{biomass\ types} Q_{biomass} \cdot EF_{biomass}$

(Equation 19)

Where:

$Q_{biomass}$ = the quantity of additional biomass that is consumed in the Certification Period to supply any on-site heat or electricity used for the capture process and the transfer of the CO₂ for storage or transport specifically, calculated in accordance with the rules in Section 3.2.3, expressed in an appropriate unit;
$EF_{biomass}$ = the emission factor, expressed in tCO₂e/unit, selected in accordance with the rules in Section 3.2.4.3.

$GHG_{bio-storage}$ refers to the CH₄ emissions due to biomass storage prior to processing at the facility where CO₂ is captured. $GHG_{bio-storage}$ shall be calculated for each quantity of feedstock of a given type that is harvested or collected at the same time and stored in the same way. $GHG_{bio-storage}$ will by set to zero for a quantity of feedstock if one or more of the following practices are followed for all biomass utilised:

biomass stored consists of coarse woody material that naturally remains well aerated;
biomass that is stored in a form that does not necessarily remain naturally aerated shall either:
be stored for no more than four weeks prior to processing;
be stored with a maximum of 30% residual moisture.
biomass is pelleted for storage;
operators otherwise demonstrate that biomass is stored in a way that avoids significant CH₄ emissions from anaerobic decomposition given the nature of the feedstock and the local conditions.

Otherwise, $GHG_{bio-storage}$ shall be calculated in accordance with Equation 20.

 $GHG_{bio-storage} = \frac{Q_{biomass}}{Q_{biomass,total}} \cdot \sum_{feedstock} \biggr(1.335 \cdot 0.0013 \cdot Q_{feedstock} \cdot C_{feedstock} \cdot (T_{storage}-1) \biggr) \cdot GWP_{CH_4}$

(Equation 20)

Where:

$Q_{biomass}$ = the quantity of additional biomass that is consumed in the Certification Period to supply any on-site heat and/or electricity used for the capture process and the transfer of the CO₂ for storage or transport specifically, calculated in accordance with the rules in Section 3.2.3, expressed in appropriate units;
$Q_{biomass,total}$ = the total quantity of biomass consumed by the capture facility in the Certification Period for both the main process generating the captured CO₂ stream and for the capture process, expressed in appropriate units;
$Q_{feedstock}$ = the quantity of the given feedstock, expressed in appropriate units;
$C_{feedstock}$ = the carbon content of the given feedstock, expressed as a mass fraction;
$T_{storage}$ = the time in months for which the feedstock is storage, rounded up;
$feedstock$ = an index of all feedstocks consumed;
$GWP_{CH_4}$ = the global warming potential of methane, 100 year basis;
$1.335$ = the mass ratio of a methane molecule to a carbon atom;
$0.0013$ = the assumed monthly fractional loss of biomass carbon from storage.

$GHG_{on-site}$ refers to the emissions due to fuel combustion and any other GHG emissions at the capture facility that are associated with the capture Activity specifically, including any CH₄ and N₂O emissions from additional biomass combustion defined in Section 3.2.3, but applying an emission factor of zero to biomass combustion. In the case that a facility requires the use of fossil fuels to start up the combustion cycle, the emissions from those fuels will not be included as they are not considered associated with the capture process specifically. In the case that fuel is consumed for biomass handling or pre-treatment, then a fraction of that fuel calculated as $\frac{Q_{biomass}}{Q_{biomass,total}}$ (See Equation 20) shall be treated as associated with the capture process specifically.

$GHG_{on-site}$ shall be calculated in accordance with Equation 21.

 $GHG_{on-site} = \sum_{fuels}(Q_{fuel} \cdot EF_{fuel}) + GHG_{other} + CO_{2\ stored,fossil}$

(Equation 21)

Where:

$Q_{fuel}$ = the quantity of fuel consumed in the Certification Period, expressed in appropriate units;
$EF_{fuel}$ = the emission factor, expressed in tCO₂e/unit, selected in accordance with the rules in Section 3.2.4.4;
$GHG_{other}$ = any other GHG emissions that are part of the capture process at the capture facility;
$CO_{2\ stored,fossil}$ = minus the quantity of fossil CO₂ from capture-related processes at the capture facility and permanently stored in tonnes CO₂. It shall calculated as $CO_{2\ captured,fossil,assoc}$ (as defined in Equation 4), plus any CO₂ losses occurring prior to storage (the calculation of losses from captured fossil CO₂ must be consistent with the calculation rules for losses of biogenic CO₂ in Section 3.1.6 and 3.1.7.

$GHG_{elec}$ refers to the emissions due to the net consumption of electricity at the capture facility for the capture process specifically, excluding own electricity consumption, calculated in accordance with Equation 22.

 $GHG_{elec} = \sum_{electricity\ sources} Q_{elec} \cdot EF_{elec}$

(Equation 22)

Where:

$Q_{elec}$ = the net quantity of electricity from each source consumed in the Certification Period for the capture process and the transfer of CO₂ for storage or transport specifically, selected in accordance with Section 3.2.2, expressed in appropriate units;
$EF_{elec}$ = the emission factor for the consumed electricity, expressed in tCO₂e/unit, selected in accordance with Section 3.2.4.1.

$GHG_{heat}$ refers to the emissions due to the net consumption of useful heat at the capture facility for the capture process specifically, excluding own heat consumption, calculated in accordance with Equation 23.

 $GHG_{heat} = \sum_{heat\ source} Q_{heat} \cdot EF_{heat}$

(Equation 23)

Where:

$Q_{heat}$ = the net quantity of useful heat consumed in the Certification Period for the capture process specifically, selected in accordance with Section 3.2.2, expressed in appropriate units;
$EF_{heat}$ = the emission factor for the consumed heat, expressed in tCO₂e/unit, selected in accordance with Section 3.2.4.2).

$GHG_{capital}$ refers to the capital emissions from the construction and installation of the carbon capture facility and shall be calculated in accordance with the principles detailed in Section 3.2.5.

$GHG_{disposal}$ refers to the emissions from the treatment and/or disposal of any wastes generated specifically due to the capture Activity, including waste from any biomass, biofuel, bioliquid or biomass fuel used for energy consumed by the capture process. This shall include emissions associated with the supply of any energy and inputs consumed in the course of waste disposal and any other GHG emissions associated with the disposal process including the emissions of CH₄ and/or N₂O due to aerobic or anaerobic degradation of the fraction of biogenic wastes associated with additional biomass use. Isometric may allow Activities to estimate disposal emissions where direct measurement would be unduly burdensome, and Operators may use default values for disposal emissions where these are provided by Isometric for specific activity types.

3.1.5.3.2

Emissions From Inputs I

Where there are inputs including chemicals consumed by the capture facility, the emissions associated with the consumption of these inputs during the Certification Period shall be calculated in accordance with Equation 24.

 $GHG_{inputs} = \sum_{inputs} Q_{input} \cdot EF_{input}$

(Equation 24)

Where:

$Q_{input}$ = the quantity of the input consumed in the Certification Period for the capture process specifically, expressed in appropriate units;
$EF_{input}$ = the emission factor for the input consumed, expressed in tCO₂e/unit, selected in accordance with Section 3.2.4.4.

The Operator may round any number of inputs who collective emissions are considered non-material on the basis of a Materiality assessment and substitute for them an emission term equal to $1\% \cdot GHG_{associated}$ , i.e., a group of inputs for which, when taking a high-end estimate of expected associated emissions:

 $\sum_{inputs} Q_{input} \cdot EF_{input} \lt 1\% \cdot CR_{total}$

(Equation 25)

3.1.5.4

Monitoring and Reporting I

In accordance with Section 2.3.3, Operators shall include in the monitoring report before each Re-Certification Audit, the measured or calculated parameters listed in Table 3. Where a parameter is noted as to be monitored, it shall be included in the Monitoring Plan in accordance with Section 2.3.2.

Table 3: Parameters for inclusion in the monitoring report.

Equation	Parameter	Unit	Definition	Notes
Equations 1, 2, 7 and 17	$CO_{2\ captured,total}$	tCO₂	The total amount of CO₂ that is captured at the capture facility and transferred for transport or storage.	Calculated using Equation 1
Equation 1	$CO_{2\ OUT,activity,i}$	tCO₂	The amount of CO₂ from the capture Activity leaving the capture facility at each exit point $i$ .	To be monitored
Equations 2, 6, 7 and 8	$CO_{2\ captured,atmobio}$	tCO₂	The amount of CO₂ of biogenic origin captured at the capture facility and transferred for transport or storage.	Calculated using Equation 2
Equations 2 and 3	$CO_{2\ captured,fossil}$	tCO₂	The amount of fossil CO₂ from processes associated with the Activity that is captured at the capture facility and transferred for transport or storage.	Calculated using Equation 3
Equations 3, 4, 5 and 6	$CO_{2\ captured,fossil,assoc}$	tCO₂	The amount of fossil CO₂ emitted as a result of the capture process that is captured.	Calculated using Equation 4
Equation 3, 5 and 17	$CO_{2\ captured,fossil,mixed}$	tCO₂	The amount of fossil CO₂ captured from a mixed stream as part of a Bio-CCS Activity.	Calculated using Equation 5
Equation 4	$CO_{2\ fossil,assoc,co\text{-}captured}$	tCO₂	The amount of CO₂ emitted as a result of the capture process that is co-captured with the biogenic CO₂.	To be monitored or calculated
Equation 4	$CO_{2\ fossil,assoc,source}$	tCO₂	The amount of CO₂ emitted as a result of the capture process that is captured separately.	To be monitored
Equation 5	$F_B$	%	For a Bio-CCS Activity capturing CO₂ from a mixed stream, the fraction of captured CO₂ that is of biogenic origin.	To be monitored
Equations 6, 27, 28 and 35	$CO_{2\ activity}$	tCO₂	The amount of CO₂ for which transport and/or storage emissions shall be counted towards the term $GHG_{associated}$ .	Calculated using Equation 6
Equations 6, 7, 7 and 9	$F_{CRCF}$	ratio	The fraction of the captured CO₂ of biogenic origin that shall be counted towards the total carbon removal.
Equation 17	$GHG_{capture}$	tCO₂e	The total GHG emissions associated with the capture of CO₂.	Calculated using Equation 17
Equations 17 and 18	$GHG_{facility}$	tCO₂e	The total GHG emissions from all relevant activities required for CO₂ capture at the capture facility.	Calculated using Equation 18
Equations 17 and 24	$GHG_{inputs}$	tCO₂e	The total GHG emissions associated with inputs to the capture facility.	Calculated using Equation 24
Equation 18 and 19	$GHG_{bio}$	tCO₂e	The emissions due to additional biomass use for energy consumed by the capture process.	Calculated using Equation 19
Equation 18 and 20	$GHG_{bio\text{-}storage}$	tCO₂e	The CH₄ emissions due to biomass storage prior to processing at the facility where CO₂ is captured.	Calculated using Equation 20
Equations 18 and 21	$GHG_{on\text{-}site}$	tCO₂e	The emissions due to fuel combustion and any other GHG emissions at the capture facility for the capture process specifically, including CH₄ and N₂O emissions from additional biomass combustion but applying a CO₂ emission factor of zero to biomass combustion.	Calculated using Equation 21
Equations 18 and 22	$GHG_{elec}$	tCO₂e	The emissions due to net consumption of electricity at the capture facility.	Calculated using Equation 22
Equation 18 and 23	$GHG_{heat}$	tCO₂e	The emissions due to net consumption of useful heat at the capture facility.	Calculated using Equation 23
Equation 18 and 73	$GHG_{capital}$	tCO₂e	The capital emissions.	Calculated using Equation 73
Equation 18	$GHG_{disposal}$	tCO₂e	The emissions from waste disposal.	To be monitored where relevant
Equation 19	$Q_{biomass}$	[appropriate unit]	The quantity of additional biomass that is consumed in the Certification Period to supply any on-site heat and/or electricity used for the capture process specifically.	To be monitored.
Equation 19	$EF_{biomass}$	tCO₂e/unit	The emission factor for additional biomass consumed.
Equation 20	$Q_{feedstock}$	[appropriate unit]	The quantity of the feedstock.	To be monitored where relevant
Equation 20	$C_{feedstock}$	%	The carbon content of the feedstock.	To be monitored where relevant
Equation 20	$T_{storage}$	months	The time in months for which the feedstock is stored.	To be monitored where relevant
Equation 21	$Q_{fuel}$	[appropriate unit]	The quantity of the fuel consumed in the Certification Period.	To be monitored
Equation 21	$EF_{fuel}$	tCO₂e	The emission factor for the consumed fuel.
Equation 21	$CO_{2\ stored,fossil}$	tCO₂	The quantity of fossil CO₂ from fuel combustion at the capture facility captured and permanently stored.	To be monitored
Equation 22	$Q_{elec}$	[appropriate unit]	The net quantity of electricity from each source consumed in the Certification Period for the capture process.	To be monitored
Equation 22	$EF_{elec}$	tCO₂e	Emission factor for the consumed electricity.
Equation 23	$Q_{heat}$	[appropriate unit]	The net quantity of useful heat consumed in the Certification Period for the capture process.	To be monitored
Equation 23	$EF_{heat}$	tCO₂e	The emission factor for the consumed heat.
Equation 24	$Q_{input}$	[appropriate unit]	The net quantity of the input consumed in the Certification Period for the capture process.	To be monitored
Equation 24	$EF_{input}$	tCO₂e	The emission factor for input consumed.
Equations 73 and 74	$GHG_{materials}$	tCO₂e	The emissions from the materials utilised in the construction of the facility.	Calculated using Equation 74
Equation 74	$Q_{materials}$	t	The quantity of materials utilised in the construction of the facility.
Equation 74	$EF_{materials}$	tCO₂e/t of material	The emission factor for the utilised materials.

3.1.6

Transport of CO|2

Transport of CO₂

This section provides rules for the quantification of GHG emissions associated with CO₂ transportation activities via pipelines, road, rail or water transportation, and their infrastructure including intermediate storage, as well as losses of CO₂ occurring during this process.

These rules apply to activities that transport captured CO₂ as a concentrated CO₂ stream from a capture facility to one or more storage sites using one or more modes of CO₂ transportation. The transport pathway from the capture facility to the storage sites consists of one or more segments of transport infrastructure as defined in Article 3, point (29), of Regulation (EU) 2024/1735 of the European Parliament and of the Council, which may be parts of one or more transport networks as defined in Article 3, point (22), of Directive 2009/31/EC. Where relevant data is available from reporting under Implementing Regulation (EU) 2018/2066, that data shall be considered reliable for the purpose of calculating transport emissions for the Activity.

Article 3 of Directive 2009/31/EC

For the purposes of this Regulation, the following definitions apply: point (29): ‘CO₂ transport infrastructure’ means the network of pipelines, including associated booster stations, for the transport of CO₂ to the storage site, as well as any ships, road or rail transport modes, including liquefaction devices and temporary storage sites if needed, for the transport of CO₂ to the harbour facilities and storage site;point (22): ‘net-zero regulatory sandbox’ means a scheme that enables undertakings to test innovative net-zero technologies and other innovative technologies in a controlled real-world environment, under a specific plan, developed and monitored by a competent authority;

Transport infrastructure segments shall be designated in order to allow the allocation of transport-related emissions in the case that CO₂ from more than one source passes through parts of the same transport network. If CO₂ captured by a single removal Activity is the only CO₂ passing through the relevant transport infrastructure, the whole transport pathway may be designated as a single transport infrastructure segment. Otherwise, the transport pathway shall be divided into a series of transport infrastructure segments. A new transport infrastructure segment shall be designated at least every time two or more CO₂ streams are merged, or two or more CO₂ streams are separated. Additional transport infrastructure segments may be specified at the discretion of the Operator or by the Certification Body for organisational reasons.

An allocation fraction, termed $F_S$ , shall be specified for each transport infrastructure segment $S$ as the fraction of the CO₂ passing through the segment in a Certification Period that comes from the Activity and is being sent for storage (i.e., not including any CO₂ coming from the Activity that is being transferred for utilisation) in accordance with Equation 26.

 $F_S = \frac{CO_{2\ activity,S}}{CO_{2\ total,S}}$

(Equation 26)

Where:

$CO_{2\ total,S}$ = the total amount of CO₂ from all sources passing through the CO₂ infrastructure segment S in the Certification Period, in tCO₂;
$CO_{2\ activity,S}$ = the amount of CO₂ from the Activity that is being transferred for permanent storage passing through the CO₂ infrastructure segment S in the Certification Period, in tCO₂. For the first infrastructure segment in the transport pathway, this is equal to the part of the Activity CO₂ ( $CO_{2\ activity}$ ) measured as transferred from the capture facility to the infrastructure segment. This excludes any CO₂ that is not biogenic that was captured from a mixed CO₂ stream. For subsequent infrastructure segments, this is the quantity of Activity CO₂ entering the previous infrastructure segment minus any CO₂ losses in that infrastructure segment, and where the CO₂ stream is split at a node to be sent to multiple storage sites the Activity CO₂ shall be allocated across the infrastructure segments leaving that node;
$S$ = the index of the transport infrastructure segment.

Operators may utilise independently verified $F_S$ values provided by CO₂ network operators.

In the case that the CO₂ passing through a transport infrastructure segment is a mix of biogenic CO₂ and fossil CO₂ emitted as a result of the capture process that was captured, then any losses shall be considered to consist of a pro-rata mix of biogenic CO₂ and fossil CO₂.

3.1.6.1

Quantification of Fugitive, Vented and Leaked Emissions of Captured CO|2

Quantification of Fugitive, Vented and Leaked Emissions of Captured CO₂

In the event of intentional or accidental losses of transported CO₂ throughout the transport network, if the quantity $CR_{total}$ is calculated based on Equation 8, these losses shall be explicitly quantified. Quantification rules are based on Implementing Regulation (EU) 2018/2066, which sets out the following two methods for the quantification of GHG emissions due to the operation of pipeline transport network: Method A, based on the overall mass balance of all input and output streams across an infrastructure segment or series of segments; and Method B, relying on the monitoring of emission sources individually, as included below. Operators may choose which of the two approaches to use for each infrastructure segment or series of segments. Operators shall choose the method that leads to lower uncertainty of the overall emissions without incurring disproportionate costs.

3.1.6.1.1

CO|2| Losses: Method A

CO₂ Losses: Method A

Operators shall quantify $CO_{2\ transport,losses}$ , the intentional and accidental losses of biogenic CO₂ being sent for permanent storage to generate carbon removal units throughout the transport segment or segments in accordance with Equation 27.

 $CO_{2\ transport,losses} = \left(\frac{F_{CRCF} \cdot CO_{2\ captured,atmobio}}{CO_{2\ activity}} \right) \cdot \sum_{S} \Big(F_S \cdot (CO_{2\ in,S} - CO_{2\ out,S}) \Big)$

(Equation 27)

Where:

$F_{CRCF}$ = defined in Section 3.1.3.2;
$CO_{2\ captured,atmobio}$ = defined in Equation 2;
$CO_{2\ activity}$ = defined in Equation 6;
$F_S$ = defined in Equation 26;
$CO_{2\ in,S}$ = the amount of CO₂ entering transport infrastructure segment $S$ , determined in accordance with Articles 40 to 46 and Article 49 of Implementing Regulation (EU) 2018/2066, in tCO₂;
$CO_{2\ out,S}$ = the amount of CO₂ leaving transport infrastructure segment $S$ , determined in accordance with Articles 40 to 46 and Article 49 of Implementing Regulation (EU) 2018/2066, in tCO₂;
$S$ = the index of the transport infrastructure segments.

Article 40 to Article 46 of Implementing Regulation (EU) 2018/2066

Article 40 Use of the measurement-based monitoring methodologyThe Project Proponent must 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 Project Proponent 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 requirements1. for each major emission source, the Project Proponent must 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 Project Proponent 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.- for emissions from minor emission sources, the Project Proponent may apply a lower tier than required in accordance with the first subparagraph of paragraph 1, 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 of paragraph 1 is technically not feasible or incurs unreasonable costs.Article 42 Measurement standards and laboratories1. all measurements must 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 must 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 must be used, limiting sampling and measurement bias. The Project Proponent must consider all relevant aspects of the continuous measurement system, including the location of the equipment, calibration, measurement, quality assurance and quality control.- the Project Proponent must ensure that laboratories carrying out measurements, calibrations and relevant equipment assessments for CEMS are accredited in accordance with EN ISO/IEC 17025 for the relevant analytical methods or calibration activities. Where the laboratory does not have such accreditation, the Project Proponent must ensure that equivalent requirements of Article 34(2) and (3) are met.Article 43 Determination of emissions1. the Project Proponent must determine the annual emissions from an emission source over the Reporting Period by summing up over the Reporting Period all hourly values of the measured greenhouse gas concentration multiplied by the hourly values of the flue gas flow, where the hourly values must be averages over all individual measurement results of the respective operating hour. In the case of CO₂ emissions, the Project Proponent must determine annual emissions on the basis of equation 1 in Annex VIII. CO emitted to the atmosphere must be treated as the molar equivalent amount of CO₂. In the case of nitrous oxide (N₂O), the Project Proponent must determine annual emissions on the basis of the equation in subsection B.1 of section 16 of Annex IV.- where several emission sources exist in one installation and cannot be measured as one emission source, the Project Proponent must measure emissions from those sources separately and add the results to obtain the total emissions of the gas in question over the Reporting Period.- the Project Proponent must 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 Project Proponent's monitoring plan.- where relevant, the Project Proponent must determine separately any CO₂ amount stemming from biomass and subtract it from the total measured CO₂ emissions. For this purpose the Project Proponent 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 Project Proponent 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) must be applied.- the Project Proponent must 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 aggregation1. the Project Proponent must calculate hourly averages for each parameter, including concentrations and flue gas flow, relevant for determining emissions using a measurement-based methodology by using all data points available for that specific hour.Where an Project Proponent can generate data for shorter reference periods without additional cost, the Project Proponent must use those periods for the determination of the annual emissions in accordance with Article 43(1).2. where the continuous measurement equipment for a parameter is out of control, out of range or out of operation for part of the hour or reference period referred to in paragraph 1, the Project Proponent must calculate the related hourly average pro rata to the remaining data points for that specific hour or shorter reference period, provided that at least 80 % of the maximum number of data points for a parameter are available.Article 45(2) to (4) must apply where fewer than 80 % of the maximum number of data points for a parameter are available.Article 45 Missing data1. where a piece of measurement equipment within a CEMS is out of operation for more than five consecutive days in any calendar year, the Project Proponent must inform the competent authority without undue delay and propose adequate measures to improve the quality of the CEMS in question;
where a valid hour or shorter reference period in accordance with Article 44(1) of data cannot be provided for one or more parameters of the measurement-based methodology due to the equipment being out of control, out of range or out of operation, the Project Proponent must determine values for substituting each missing hour of data;
where a valid hour or shorter reference period of data cannot be provided for a parameter directly measured as concentration, the Project Proponent must calculate a substitution value as the sum of an average concentration and twice the standard deviation associated with that average, using equation 4 in Annex VIII.Where the Reporting Period is not applicable for determining such substitution values due to significant technical changes at the installation, the Project Proponent must agree with the competent authority a representative timeframe for determining the average and standard deviation, where possible with a duration of one year.4. where a valid hour of data cannot be provided for a parameter other than concentration, the Project Proponent must obtain substitute values of that parameter through a suitable mass balance model or an energy balance of the process. The Project Proponent must validate the results by using the remaining measured parameters of the measurement-based methodology and data at regular working conditions, considering a time period of the same duration as the data gap.Article 46 Corroborating with calculation of emissionsThe Project Proponent must 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 must not be required.

Article 49 of Implementing Regulation (EU) 2018/2066

Article 49 Transferred CO₂1. the Project Proponent must 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:(a) transferred out of the installation to any of the following:(i) a capture installation for the purpose of transport and long-term geological storage in a storage site permitted under Directive 2009/31/EC;(ii) a transport network with the purpose of long-term geological storage in a storage site permitted under Directive 2009/31/EC;(iii) a storage site permitted under Directive 2009/31/EC for the purpose of long-term geological storage;(b) transferred out of the installation and used to produce precipitated calcium carbonate, in which the used CO₂ is chemically bound.2. in its annual emissions report, the Project Proponent of the transferring installation must provide the receiving installation's installation identification code recognised in accordance with the acts adopted pursuant to Article 19(3) of Directive 2003/87/EC, if the receiving installation is covered by that Directive. In all other cases, the Project Proponent of the transferring installation must provide the name, address and contact information of a contact person for the receiving installation.The first subparagraph must also apply to the receiving installation with respect to the transferring installation's installation identification code.3. for the determination of the quantity of CO₂ transferred from one installation to another, the Project Proponent must apply a measurement-based methodology, including in accordance with Articles 43, 44 and 45. The emission source must correspond to the measurement point and the emissions must be expressed as the quantity of CO₂ transferred.For the purpose of point (b) of paragraph 1, the Project Proponent must apply a calculation-based methodology.4. for determining the quantity of CO₂ transferred from one installation to another, the Project Proponent must apply the highest tier as defined in section 1 of Annex VIII.However, the Project Proponent 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 Project Proponent must use data sources representing highest achievable accuracy.5. the Project Proponents may determine quantities of CO₂ transferred out of the installation both at the transferring and at the receiving installation. In such cases, Article 48(3) must apply.

3.1.6.1.2

CO|2| Losses: Method B

CO₂ Losses: Method B

Operators shall quantify $CO_{2\ transport,losses}$ based on the intentional and accidental losses of biogenic CO₂ being sent for permanent storage to generate carbon removal units throughout the transport segment or segments, in accordance with Equation 28.

 $CO_{2\ transport,losses} = \frac{F_{CRCF} \cdot CO_{2\ captured,atmobio}}{CO_{2\ activity}} \cdot \sum_{S} \Big( F_S \cdot (CO_{2\ fugitive,S} + CO_{2\ vented,S} + CO_{2\ leakage,S} ) \Big)$

(Equation 28)

Where:

$F_{CRCF}$ = defined in Section 3.1.3.2;
$CO_{2\ captured,atmobio}$ = defined in Equation 2;
$CO_{2\ activity}$ = defined in Equation 6;
$F_S$ = defined in Equation 26;
$CO_{2\ fugitive,S}$ = the sum of fugitive emissions from CO₂ transported in the transportation infrastructure, such as from seals, valves, intermediate compressor stations in pipeline structures and intermediate storage sites, in tCO₂;
$CO_{2\ vented,S}$ = the sum of vented emissions from CO₂ transported in the transportation infrastructure, in tCO₂;
$CO_{2\ leakage,S}$ = the sum of CO₂ transported in the transportation infrastructure, which is emitted as the result of the failure of one or more components of the network, in tCO₂;
$S$ = the index of the transport infrastructure segments.

3.1.6.1.3

Fugitive Emissions

Fugitive emissions during CO₂ transportation in any of the following components: (a) seals; (b) measurement devices; (c) valves; (d) intermediate compressor stations; (e) intermediate storage sites shall be calculated in accordance with Equation 29.

 $CO_{2\ fugitive} = \sum_{S} \left( \sum_{c} (EF_{occur,c,S} \cdot N_{occur,c,S}) \right)$

(Equation 29)

Where:

$F_S$ = defined in Equation 26;
$EF_{occur,c,S}$ = the average emission factors per component per time period, expressed in tCO₂/unit time. $EF_{occur,c}$ shall be determined for each type of component. These factors shall be reviewed at least every 5 years based on newly available techniques and knowledge;
$N_{occur,c,S}$ = the number of components type $c$ in the transportation system, multiplied by the number of time periods;
$c$ = the type of component: seals; measurement devices; valves; intermediate compressor stations; and intermediate storage sites;
$S$ = the index of the transport infrastructure segments.

Isometric may provide lists of default fugitive emissions factors for relevant equipment.

3.1.6.1.4

Vented Emissions

Operators shall calculate $CO_{2\ vented}$ for each transport infrastructure segment $S$ as the expected venting identified for that transport infrastructure segment by the operator of the transport network. If the operator of the transport network does not provide venting emissions at the disaggregated level of the transport infrastructure segment, venting emissions shall be allocated by segment on a reasonable basis to be agreed by the Operator and the Certification Body.

3.1.6.1.5

Leakage Events

The Implementing Regulation (EU) 2018/2066 requires that each transport network operator shall monitor the transport network and calculate the amount of CO₂ leaked from the transport with a suitable methodology documented in the Monitoring Plan, based on industry best practice guidelines.

Operators shall calculate $CO_{2\ leakage}$ for each transport infrastructure segment $S$ as the amount of leakage identified for that transport infrastructure segment by the operator of the transport network during the Certification Period. If the operator of the transport network does not report leakage emissions at the disaggregated level of the transport infrastructure segment, leakage emissions shall be allocated for each segment on a reasonable basis to be agreed by the Operator and the Certification Body.

3.1.6.2

Quantification of Associated GHG Emissions for Transport

GHG emissions associated with the transportation of CO₂ (for vehicles and/or in the supporting infrastructure) shall be calculated in accordance with Equation 30.

 $GHG_{transport} = \sum_{S} \left(F_S \cdot \biggr(\sum_{T} GHG_{T,S} + GHG_{infra,S} \biggr) \right)$

(Equation 30)

Where:

$F_S$ = defined in Equation 26;
$GHG_{T,S}$ = the GHG emissions due to energy use for CO₂ transportation in mode of transport type $T$ , in infrastructure segment $S$ , in tCO₂e;
$GHG_{infra}$ = the GHG emissions due to energy use at the supporting infrastructure connected to the CO₂ transport network, including pipeline operation infrastructure, in tCO₂e;
$T$ = the transport type for the infrastructure segment (e.g., road, rail or maritime);
$S$ = the index of the transport infrastructure segments.

3.1.6.2.1

Emissions From Non-Pipeline Transportation of CO|2

Emissions From Non-Pipeline Transportation of CO₂

Following the principles in Section 3.2.4.5, GHG emissions associated with the non-pipeline transport of CO₂ by transportation mode $T$ in each transport infrastructure segment, $GHG_{T,S}$ , shall either be calculated based on actual data on fuel consumption in accordance with Equation 31, or based on vehicle efficiencies and actual data about vehicle distance travelled in accordance with Equation 32. Operators are permitted to use different approaches for different transport modes and infrastructure segments.

 $GHG_{T,S} = \sum_{trips} \Big(Q_{fuel,S} \cdot EF_{fuel} \Big)$

(Equation 31)

Where:

$Q_{fuel,S}$ = the quantity of fuel consumed for each trip in infrastructure segment $S$ , including empty return trips, expressed in appropriate units;
$EF_{fuel}$ = the emission factor for the consumed fuel, expressed in tCO₂e/unit, selected in accordance with the rules in Section 3.2.4.4;
$trips$ = an index of the trips taken.

 $GHG_{T,S} = \left(\sum_{L=1}^{O} \Big(K_{L,S} \cdot EF_{vehicle,loaded} \Big) + \sum_{L=1}^{R} \Big(K_{L,S} \cdot EF_{vehicle,unloaded} \Big) \right)$

(Equation 32)

Where:

$K_{L,S}$ = the distance of each trip in infrastructure segment $S$ in kilometres;
$EF_{vehicle, loaded}$ = the CO₂ emissions per kilometre of the vehicle when loaded, in tCO₂/km travelled. This may be based on an appropriate conservative default emission factor if it has been provided by Isometric;
$EF_{vehicle,unloaded}$ = the CO₂ emissions per kilometre of the vehicle when unloaded, in tCO₂/km travelled. This may be based on an appropriate conservative default emissions factor if it has been provided by Isometric. If no data/default is available for the vehicle but a value is available for $EF_{vehicle,loaded}$ then the Operator may set $EF_{vehicle,unloaded} = EF_{vehicle,loaded}$ ;
$O$ = the total number of outbound trips taken;
$R$ = the total number of empty return trips taken;
$L$ = an index of the trips.

3.1.6.2.2

Emissions From Transportation Infrastructure

GHG emissions due to fuel and electricity consumption across all processes at installation required to operate the transport network shall be calculated according to Equation 33. Operators may use default values for emissions from transportation infrastructure where such default values are provided by Isometric.

 $GHG_{infra} = \sum_{S} \left(F_S \cdot \sum_{f} \biggr(Q_{stat,f} \cdot EF_f + Q_{mob,f} \cdot EF_f \biggr) + Q_{elec} \cdot EF_{elec}\right)$

(Equation 33)

Where:

$Q_{stat,f}$ = the quantity of fuel type $f$ combusted in stationary sources at the installed infrastructure, in giga joule (GJ);
$Q_{mob,f}$ = the quantity of fuel type $f$ combusted in mobile sources at the installed infrastructure, in GJ;
$EF_f$ = the emission factor due to the combustion of the fuel type $f$ , in tCO₂e/GJ, chosen following Section 3.2.4.4;
$Q_{elec}$ = the net amount of electricity imported from the grid and consumed at the installed infrastructure, selected in accordance with Section 3.2.2;
$EF_{elec}$ = the emission factor for the generation of electricity in tCO₂e/MWh chosen following Section 3.2.4.1;
$f$ = fuel type, including those from fossil and biogenic origin.

3.1.6.3

Monitoring and Reporting II

In accordance with Section 2.3.3, Operators shall include in the monitoring report before each Re-Certification Audit, the measured or calculated parameters listed in Table 4. Where a parameter is noted as to be monitored, it shall be included in the Monitoring Plan in accordance with Section 2.3.2.

Table 4: Parameters for inclusion in the monitoring report.

Equation	Parameter	Unit	Definition	Notes
Equation 26	$F_S$	%	The allocation fraction defined for each transport segment $S$ as the fraction of the CO₂ from the Activity passing through the segment in a Certification Period and is being sent for storage.	Calculated using Equation 26
Equation 26	$CO_{2\ activity,S}$	tCO₂	The amount of CO₂ from the Activity passing through the CO₂ infrastructure segment $S$ in the Certification Period.	To be monitored
Equation 26	$CO_{2\ total,S}$	tCO₂	Total amount of CO₂ from all sources passing through the CO₂ infrastructure segment $S$ in the Certification Period.	To be monitored
Equations 8, 27 and 28	$CO_{2\ transport,losses}$	tCO₂	Amount of losses of biogenic CO₂ being sent for permanent storage to generate carbon removal units throughout the transport network.	Calculated using Equation 27 or Equation 28
Equation 27	$CO_{2\ in,S}$	tCO₂	Amount of CO₂ transferred to the transport infrastructure segment $S$ , determined in accordance with Articles 40 to 46 and Article 49 of Commission Implementing Regulation (EU) 2018/2066.	To be monitored
Equation 27	$CO_{2\ out,S}$	tCO₂	Amount of CO₂ transferred out of the transport infrastructure segment, determined in accordance with Articles 40 to 46 and Article 49 of Commission Implementing Regulation (EU) 2018/2066.	To be monitored
Equations 28 and 29	$CO_{2\ fugitive,S}$	tCO₂	Sum of fugitive emissions from CO₂ transported in the transportation infrastructure.	Calculated using Equation 29
Equation 28	$CO_{2\ vented,S}$	tCO₂	Sum of vented emissions from CO₂ transported in the transportation infrastructure.	To be informed by the operator of the transport network
Equation 28	$CO_{2\ leakage,S}$	tCO₂	Sum of CO₂ transported in the transportation infrastructure, which is emitted as the result of the failure of one or more components of the network.	To be informed by the operator of the transport network.
Equation 29	$EF_{occur,c,S}$	tCO₂e/unit time	Average emission factors per type of component per occurrence.	To be monitored
Equation 29	$N_{occur,c,S}$	number of time units/year	Number of components in the transportation system per type of component.	To be monitored
Equation 30	$GHG_{transport}$	tCO₂e	Total amount of GHG emissions from the combustion of fuels during the transportation of CO₂.	Calculated using Equation 30
Equations 30, 31 and 32	$GHG_{T,S}$	tCO₂e	Emissions due to energy use for CO₂ transportation in mode of transportation type $T$ in infrastructure segment $i$ .	Calculated using Equation 31 or Equation 32
Equations 30 and 33	$GHG_{infra,S}$	tCO₂e	Emissions due to energy use at the supporting infrastructure connected to the CO₂ transport network.	Calculated using Equation 33
Equation 31	$Q_{fuel}$	[appropriate unit]	Quantity of the fuel consumed in the Certification Period.	To be monitored
Equation 31	$EF_{fuel}$	tCO₂e	Emission factor for consumed fuel.
Equation 32	$K_{L,S}$	km	Distances of trips in infrastructure segments $S$ .	To be monitored
Equation 32	$EF_{vehicle,loaded}$	tCO₂e/km	CO₂ emission per kilometre of the loaded transport vehicles.
Equation 32	$EF_{vehicle,unloaded}$	tCO₂e/km	CO₂ emission per kilometre of the unloaded transport vehicles.
Equation 33	$Q_{stat,f}$	GJ	Quantity of fuel type $f$ combusted in stationary sources at the installed infrastructure.	To be monitored. Where relevant, the density and Net Calorific Value used shall be reported.
Equation 33	$Q_{mob,f}$	GJ	Quantity of fuel type $f$ combusted in mobile sources at the installed infrastructure.	To be monitored
Equation 33	$Q_{elec}$	MWh	Amount of electricity imported from the grid and consumed at the installed infrastructure.	To be monitored
Equation 33	$EF_f$	tCO₂e/GJ	Emission factor due to the combustion of the fuel type $f$ .
Equation 33	$EF_{elec}$	tCO₂e/MWh	Emissions factor for the generation of electricity.

3.1.7

Injection of CO|2| at Storage Sites

Injection of CO₂ at Storage Sites

A CO₂ capture Activity may transfer CO₂ via a transport pathway to one or more storage sites for injection into geological storage. If CO₂ from sources other than the Activity is stored at the same site, an allocation fraction shall be defined for each storage site $S$ as the fraction of the CO₂ stored at that facility in a Certification Period that comes from the Activity in accordance with Equation 34.

 $F_S = \frac{CO_{2\ activity,injected,S}}{CO_{2\ injected,S}}$

(Equation 34)

Where:

$CO_{2\ activity,injected,S}$ = the part of $CO_{2\ activity}$ (see Equation 6) that is stored at site S. In the case of a non-segregated CO₂ stream this amount shall be specified on a mass balance basis;
$CO_{2\ injected}$ = the total amount of CO₂ from all sources stored at site S in the Certification Period;
$S$ = the index of the storage sites.

3.1.7.1

Quantification of CO|2| Entering the Storage Site

Quantification of CO₂ Entering the Storage Site

The amount of CO₂ entering the storage site shall be determined at the entry point or points using a measurement-based approach in accordance with Articles 40 to 45 and Article 49 of Implementing Regulation (EU) 2018/2066.

Article 40 to 45

Article 40: Use of the measurement-based monitoring methodologyThe 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 requirementsFor each major emission source, the operator shall apply the following:a) in the case of a category A installation, at least the tiers listed in section 2 of Annex VIII;b) 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.For emissions from minor emission sources, the operator may apply a lower tier than required in accordance with the first subparagraph of paragraph 1, 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 of paragraph 1 is technically not feasible or incurs unreasonable costs.Article 42 Measurement standards and laboratories1. all measurements shall be carried out applying methods based on:a) EN 14181 (Stationary source emissions — Quality assurance of automated measuring systems);b) EN 15259 (Air quality — Measurement of stationary source emissions — Requirements for measurement sections and sites and for the measurement objective, plan and report);c) 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.2. the operator shall ensure that laboratories carrying out measurements, calibrations and relevant equipment assessments for CEMS are accredited in accordance with EN ISO/IEC 17025 for the relevant analytical methods or calibration activities.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 emissions1. the operator shall determine the annual emissions from an emission source over the reporting period by summing up over the reporting period all hourly values of the measured greenhouse gas concentration multiplied by the hourly values of the flue gas flow, where the hourly values shall be averages over all individual measurement results of the respective operating hour.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.2. where several emission sources exist in one installation and cannot be measured as one emission source, the operator shall measure emissions from those sources separately and add the results to obtain the total emissions of the gas in question over the reporting period; 3. the operator shall determine the greenhouse gas concentration in the flue gas by continuous measurement at a representative point through one of the following:a) direct measurement;b) 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.4. 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) 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);b) 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);c) 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.5. the operator shall determine the flue gas flow for the calculation in accordance with paragraph 1 by one of the following methods:a) 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);b) determination by continuous flow measurement at a representative point.Article 44 Data aggregation1. the operator shall calculate hourly averages for each parameter, including concentrations and flue gas flow, relevant for determining emissions using a measurement-based methodology by using all data points available for that specific hour.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).2. where the continuous measurement equipment for a parameter is out of control, out of range or out of operation for part of the hour or reference period referred to in paragraph 1, the operator shall calculate the related hourly average pro rata to the remaining data points for that specific hour or shorter reference period, provided that at least 80 % of the maximum number of data points for a parameter are available.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 data1. where a piece of measurement equipment within a CEMS is out of operation for more than five consecutive days in any calendar year, the operator shall inform the competent authority without undue delay and propose adequate measures to improve the quality of the CEMS in question; 2. where a valid hour or shorter reference period in accordance with Article 44(1) of data cannot be provided for one or more parameters of the measurement-based methodology due to the equipment being out of control, out of range or out of operation, the operator shall determine values for substituting each missing hour of data; 3. where a valid hour or shorter reference period of data cannot be provided for a parameter directly measured as concentration, the operator shall calculate a substitution value as the sum of an average concentration and twice the standard deviation associated with that average, using equation 4 in Annex VIII.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.4. where a valid hour of data cannot be provided for a parameter other than concentration, the operator shall obtain substitute values of that parameter through a suitable mass balance model or an energy balance of the process. The operator shall validate the results by using the remaining measured parameters of the measurement-based methodology and data at regular working conditions, considering a time period of the same duration as the data gap.

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:a) transferred out of the installation to any of the following:i) a capture installation for the purpose of transport and long-term geological storage in a storage site permitted under Directive 2009/31/EC;ii) a transport network with the purpose of long-term geological storage in a storage site permitted under Directive 2009/31/EC;iii) a storage site permitted under Directive 2009/31/EC for the purpose of long-term geological storage;b) transferred out of the installation and used to produce precipitated calcium carbonate, in which the used CO2 is chemically bound.In its annual emissions report, the operator of the transferring installation shall provide the receiving installation's installation identification code recognised in accordance with the acts adopted pursuant to Article 19(3) of Directive 2003/87/EC, if the receiving installation is covered by that Directive. In all other cases, the operator of the transferring installation shall provide the name, address and contact information of a contact person for the receiving installation.The first subparagraph shall also apply to the receiving installation with respect to the transferring installation's installation identification code.For the determination of the quantity of CO2 transferred from one installation to another, the operator shall apply a measurement-based methodology, including in accordance with Articles 43, 44 and 45. The emission source shall correspond to the measurement point and the emissions shall be expressed as the quantity of CO2 transferred.For the purpose of point (b) of paragraph 1, the operator shall apply a calculation-based methodology.For determining the quantity of CO2 transferred from one installation to another, the operator shall apply the highest tier as defined in section 1 of Annex VIII.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.The operators may determine quantities of CO2 transferred out of the installation both at the transferring and at the receiving installation. In such cases, Article 48(3) shall apply.

3.1.7.2

Application of Mass Balance Rules

Other than in the case that the CO₂ stream is fully segregated and the rules in Section 3.1.3.3 are used to determine $CR_{total}$ , a mass balance system based on the following principles shall be used to trace CO₂ through the transport infrastructure from the capture facility to the storage site:

each quantity of CO₂ entering the transport and storage system may be treated as having been stored or otherwise discharged from the system (by losses and by supply for a non-storage application) only once;
the sum of the quantities of CO₂ entering, or released from intermediate storage at, any transport infrastructure segment or storage site in a given period shall be equal to the sum of the quantity of CO₂ identified as leaving or being intermediately or permanently stored at that infrastructure segment or storage site in the same period (allowing for any discrepancy associated with the quantity of CO₂ actively in transit or undergoing storage related processes at the end for the period and for measurement uncertainty);
where a quantity of CO₂ from an Activity is mixed with a quantity of CO₂ from other sources, and that mixed stream of CO₂ is then transferred to more than one subsequent transport infrastructure segment or storage site, then the Operator may agree with other interested parties which of the transferred quantities of CO₂ are to be treated as originating or partially originating from that Activity;
where a quantity of CO₂ is transferred into an interconnected transport network and thereby mixed with a quantity of CO₂ from other sources, the Operator is not required to model the transit time of the CO₂ from the Activity through the transport network - any corresponding quantity of CO₂ transferred out of the transport network after the time at which the CO₂ from the Activity enters the transport network may be treated as the CO₂ from the Activity, with the constraint that it is not permissible to assume that CO₂ has travelled against the flow direction in a transport infrastructure segment;
subject to the principles detailed in points 1-4, contractual arrangement may be used to identify a quantity of CO₂ being injected at a storage site with an equivalent quantity of CO₂ from a capture installation (accounting for losses in transit using the rules in this methodology) that was transferred into a system of shared infrastructure, even though the actual physical location of the CO₂ molecules captured by the Activity may be unknown. No other quantity of CO₂ stored by or leaving that system of shared infrastructure may be identified with the quantity of CO₂ captured by the carbon removal Activity;
operators shall provide adequate evidence (or arrange for the entities providing the transport and/or storage infrastructure services to provide adequate evidence) that the above mentioned mass balance requirements and any additional requirements imposed by Isometric have been complied with.

3.1.7.3

Quantification of Fugitive and Vented Emissions of Captured CO|2

Quantification of Fugitive and Vented Emissions of Captured CO₂

In the event of any intentional or accidental losses of CO₂ prior to entering permanent storage if the quantity $CR_{total}$ is calculated based on Equation 8, these losses shall be explicitly quantified.

Fugitive and vented emissions during injection at the storage site shall be calculated in accordance with Section 23, subsection B.1., of Annex IV to Implementing Regulation 2018/2066. For geological storage, data regarding fugitive and vented emissions shall be based on data recorded by the entity operating the storage site under Implementation Regulation (EU) 2018/2066. The total loss of CO₂ from the Activity during storage shall be calculated in accordance with Equation 35.

 $CO_{2\ storage,losses} =F_{CRCF} \cdot \frac{CO_{2\ captured,atmobio}}{CO_{2\ activity}} \cdot \sum_{S} \Biggr(F_S \cdot \Big(CO_{2\ fugitive,S} + CO_{2\ vented,S} \Big) \Biggr)$

(Equation 35)

Where:

$F_{CRCF}$ = defined in Section 3.1.3.2;
$CO_{2\ captured,atmobio}$ = defined in Equation 2;
$CO_{2\ activity}$ = defined in Equation 6;
$F_S$ = the fraction of the CO₂ stored at site $S$ that originates from the Activity, in %;
$CO_{2\ fugitive,S}$ = the fugitive CO₂ emissions from the facility $S$ , in tonnes CO₂;
$CO_{2\ vented,S}$ = the vented CO₂ emissions from facility $S$ , in tonnes CO₂.

At each facility $S$ , the sum of the fugitive and vented emissions shall be equal to the difference between the measured amount of CO₂ entering the site and the measured amount of CO₂ entering the storage reservoir, in accordance with Equation 36.

 $CO_{2\ fugitive,S} + CO_{2\ vented,S} = CO_{2\ IN,S} - CO_{2\ injected,S}$

(Equation 36)

Where:

$CO_{2\ IN,S}$ = the measured total amount of CO₂ entering the facility $S$ , in tonnes of CO₂;
$CO_{2\ injected,S}$ = the measured total amount of CO₂ entering permanent storage at the facility S, in tonnes CO₂.

Section 23, subsection B.1. of Annex IV to Implementing Regulation 2018/2066

B.1. Vented and fugitive emissions from injectionThe Project Proponent must determine emissions from venting and fugitive emissions as follows: $CO_{2} \text{ emitted [t } CO_{2} \text{]} = V \ CO_{2} \text{ [t } CO_{2} \text{]} + F \ CO_{2} \text{ [t } CO_{2} \text{]}$ Where: $V \ CO_{2}$ = amount of CO₂ vented; $F \ CO_{2}$ = amount of CO₂ from fugitive emissions.Each Project Proponent must determine V CO₂ using measurement-based methodologies in accordance with Articles 41 to 46 of this Regulation. By way of derogation from the first sentence and upon approval by the competent authority, the Project Proponent may include in the monitoring plan an appropriate methodology for determining V CO₂ based on industry best practice, where the application of measurement-based methodologies would incur unreasonable costs.The Project Proponent must 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 Project Proponent must 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 Project Proponent 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.

Article 32 to Article 35 f Directive 2009/31/EC

Article 32 Amendment of Directive 2000/60/ECIn Article 11(3)(j) of Directive 2000/60/EC, the following indent must be inserted after the third indent:injection of carbon dioxide streams for storage purposes into geological formations which for natural reasons are permanently unsuitable for other purposes, provided that such injection is made in accordance with Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide (*1) or excluded from the scope of that Directive pursuant to its Article 2(2);Article 33 Amendment of Directive 2001/80/ECIn Directive 2001/80/EC, the following Article must be inserted:Article 9a1. member States must ensure that Project Proponents of all combustion plants with a rated electrical output of 300 megawatts or more for which the original construction licence or, in the absence of such a procedure, the original operating licence is granted after the entry into force of Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide (*1), have assessed whether the following conditions are met:— suitable storage sites are available,— transport facilities are technically and economically feasible,— it is technically and economically feasible to retrofit for CO₂ capture.2. if the conditions in paragraph 1 are met, the competent authority must ensure that suitable space on the installation site for the equipment necessary to capture and compress CO₂ is set aside. The competent authority must determine whether the conditions are met on the basis of the assessment referred to in paragraph 1 and other available information, particularly concerning the protection of the environment and human health.Article 34 Amendment of Directive 2004/35/ECIn Annex III to Directive 2004/35/EC, the following paragraph must be added:‘14. the operation of storage sites pursuant to Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide (*1).Article 35 Amendment of Directive 2006/12/ECArticle 2(1)(a) of Directive 2006/12/EC must be replaced by the following:‘(a) gaseous effluents emitted into the atmosphere and carbon dioxide captured and transported for the purposes of geological storage and geologically stored in accordance with Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide (*1) or excluded from the scope of that Directive pursuant to its Article 2(2);

Annex II(1.1) of Directive 2009/31/EC

1.1. Establishing the plan The monitoring plan must provide details of the monitoring to be deployed at the main stages of the Project, including baseline, operational and post-closure monitoring. The following must be specified for each phase:(a) parameters monitored;(b) monitoring technology employed and justification for technology choice;(c) monitoring locations and spatial sampling rationale;(d) frequency of application and temporal sampling rationale.The parameters to be monitored are identified so as to fulfil the purposes of monitoring. However, the plan must in any case include continuous or intermittent monitoring of the following items:(e) fugitive emissions of CO₂ at the injection facility;(f) CO₂ volumetric flow at injection wellheads;(g) CO₂ pressure and temperature at injection wellheads (to determine mass flow);(h) chemical analysis of the injected material;(i) reservoir temperature and pressure (to determine CO₂ phase behaviour and state).The choice of monitoring technology must be based on best practice available at the time of design. The following options must be considered and used as appropriate:(j) technologies that can detect the presence, location and migration paths of CO₂ in the subsurface and at surface;(k) technologies that provide information about pressure-volume behaviour and areal/vertical distribution of CO₂-plume to refine numerical 3-D simulation to the 3-D-geological models of the storage formation established pursuant to Article 4 and Annex I;(l) technologies that can provide a wide areal spread in order to capture information on any previously undetected potential leakage pathways across the areal dimensions of the complete storage complex and beyond, in the event of significant irregularities or migration of CO₂ out of the storage complex.

3.1.7.4

Quantification of Associated GHG Emissions

The GHG emissions associated with injection at a storage site shall be calculated in accordance with Equation 37.

 $GHG_{storage} = \sum_{S} \biggr( F_S \cdot \big(GHG_{storage\ site} + GHG_{inputs} \big) \biggr)$

(Equation 37)

Where:

$GHG_{storage\ site}$ = the GHG emissions associated with energy use and operation at the storage site, in tonnes CO₂e, defined in Equation 38;
$GHG_{input}$ = the GHG emissions associated with the production and use of other inputs used at the storage site, in tonnes CO₂e.

3.1.7.4.1

Emissions From the Storage Site

The GHG emissions at each storage site shall be calculated in accordance with Equation 38.

 $GHG_{storage\ site} = GHG_{combustion} + GHG_{elec} + GHG_{heat} + GHG_{capital}$

(Equation 38)

Where:

$GHG_{combustion}$ = the GHG emissions due to fuel consumption at the storage site, in tonnes CO₂e, calculated in accordance with Equation 39 below;
$GHG_{elec}$ = the GHG emissions due to net electricity consumption at the storage site in tonnes CO₂e, calculated in accordance with Equation 40 below;
$GHG_{heat}$ = the GHG emissions due to net useful heat consumption at the storage site, in tonnes CO₂e, calculated in accordance with Equation 41;
$GHG_{capital}$ = the capital emissions from the construction and installation of the storage site, in tonnes CO₂e, calculated in accordance with the principles detailed in Section 3.2.5.

 $GHG_{combustion} = \sum_{fuels} Q_{fuel} \cdot EF_{fuel} + CO_{2\ stored,fossil}$

(Equation 39)

Where:

$Q_{fuel}$ = the quantity of the fuel consumed in the Certification Period, expressed in appropriate units;
$EF_{fuel}$ = the emission factor for the fuel consumed, expressed in tCO₂e/unit, selected in accordance with Section 3.2.4.4;
$CO_{2\ stored,fossil}$ = minus the quantity of fossil CO₂ from fuel combustion at the storage site captured and permanently stored, in tonnes of CO₂. This shall be calculated as the minus the measured quantity of CO₂ captured from fossil sources at the storage site plus any CO₂ losses prior to storage.

 $GHG_{elec} = \sum_{electricity source} Q_{elec} \cdot EF_{elec}$

(Equation 40)

Where:

$Q_{elec}$ = the net quantity of electricity consumed in the Certification Period, selected in accordance with Section 3.2.2, expressed in appropriate units;
$EF_{elec}$ = the emission factor for the consumed electricity, expressed in tCO₂e/unit, selected in accordance with Section 3.2.4.1.

 $GHG_{heat} = \sum_{heat source} Q_{heat} \cdot EF_{heat}$

(Equation 41)

Where:

$Q_{heat}$ = the net quantity of useful heat consumed in the Certification Period, selected in accordance with Section 3.2.2, expressed in appropriate units;
$EF_{heat}$ = the emission factor for the consumed heat, expressed in tCO₂e/unit, selected in accordance with Section 3.2.4.2.

3.1.7.4.2

Emissions From Inputs II

Where there are inputs consumed at the storage site the emissions associated with the consumption of these inputs during the Certification Period shall be calculated in accordance with Equation 42.

 $GHG_{inputs} = \sum_{inputs} Q_{input} \cdot EF_{input}$

(Equation 42)

Where:

$Q_{input}$ = the quantity of the input consumed in the Certification Period, expressed in appropriate units;
$EF_{input}$ = the emission factor for the input consumed, expressed in tCO₂e/unit, selected in accordance with Section 3.2.4.4.

The Operator may group any number of inputs whose collective emissions are considered non-material on the basis of a Materiality assessment and substitute for them an emission term equal to 1% $\cdot CR_{total}$ , i.e. a group of inputs for which, when taking a high-end estimate of possible associated emissions, is in accordance with Equation 43.

 $\sum_{inputs} Q_{input} \cdot EF_{input} < 1\% \cdot CR_{total}$

(Equation 43)

3.1.7.5

Monitoring and Reporting III

In accordance with Section 2.3.3, Operators shall include in the monitoring report before each Re-Certification Audit the measured or calculated parameters for the Certification Period being audited listed in Table 5. Where a parameter is noted as ‘to be monitored’, it shall be included in the Monitoring Plan in accordance with Section 2.3.2.

Table 5: Parameters for inclusion in the monitoring report.

Equation	Parameter	Unit	Definition	Notes
Equation 34	$F_S$	%	The allocation fraction of the CO₂ stored at site $S$ that originates from the Activity and shall be used to generate carbon removal units.	Calculated using Equation 34.
Equation 34	$CO_{2\ activity,injected,S}$	tCO₂	The part of $CO_{2\ activity}$ stored at site $S$ .	To be identified following mass balance rules in the case of non-segregated CO₂ streams.
Equations 34 and 36	$CO_{2\ injected,S}$	tCO₂	The total amount of CO₂ injected for permanent storage at each relevant storage site.	To be monitored.
Equations 8 and 35	$CO_{2\ storage,losses}$	tCO₂	The amount of losses of biogenic CO₂ being sent for permanent storage to generate carbon removal units during storage activity.	Calculated using Equation 35.
Equations 35 and 36	$CO_{2\ vented,S}$	tCO₂	The amount of CO₂ vented at each relevant storage site.	To be monitored.
Equations 35 and 36	$CO_{2\ fugitive,S}$	tCO₂	The amount of CO₂ fugitives at each relevant storage site.	To be monitored or calculated using Equation 36.
Equation 36	$CO_{2\ IN,S}$	tCO₂	The amount of CO₂ entering the storage site $S$ .	To be monitored.
Equation 37	$GHG_{storage}$	tCO₂e	The GHG emissions associated with the injection at a storage site.	Calculated using Equation 37.
Equations 37 and 38	$GHG_{storage\ site}$	tCO₂e	The GHG emissions associated with energy use and operation at the storage site.	Calculated using Equation 38.
Equations 37 and 42	$GHG_{inputs}$	tCO₂e	The GHG emissions associated with the production and use of other inputs used at the storage site.	Calculated using Equation 42.
Equations 38 and 39	$GHG_{combustion}$	tCO₂e	The GHG emissions due to fuel consumption at the storage site.	Calculated using Equation 39.
Equations 38 and 40	$GHG_{elec}$	tCO₂e	The GHG emissions due to net electricity consumption at the storage site.	Calculated using Equation 40.
Equations 38 and 41	$GHG_{heat}$	tCO₂e	The GHG emissions due to net useful heat consumption at the storage site.	Calculated using Equation 41.
Equations 38 and 73	$GHG_{capital}$	tCO₂e	The capital emissions.	To be informed by the Operator. Calculated using Equation 73.
Equation 39	$Q_{fuel}$	[appropriate unit]	The amount of fuels used for combustion at each storage site.	To be monitored.
Equation 39	$EF_{fuel}$	tCO₂e/unit	The emission factor for the fuel consumed.
Equation 40	$Q_{elec}$	MWh	The net amount of electricity consumed at each storage site.	To be monitored.
Equation 40	$EF_{elec}$	tCO₂e/unit	The emission factor for the consumed electricity.
Equation 41	$Q_{heat}$	MWh	The net amount of useful heat consumed at the storage site, for all relevant storage sites.	To be monitored.
Equation 41	$EF_{heat}$	tCO₂e/unit	The emission factor for the consumed heat.
Equation 42	$Q_{input}$	[appropriate unit]	The amount of input consumed.	To be monitored.
Equation 42	$EF_{input}$	tCO₂e/unit	The emission factor for the input consumed.
Equations 73 and 74	$GHG_{materials}$	tCO₂e	The emissions from the materials utilised in the construction of the storage site.	Calculated using Equation 74.
Equation 74	$Q_{materials}$	tonne	The quantity of materials utilised in the construction of the storage site.	To be monitored.
Equation 74	$EF_{materials}$	tCO₂e/tonne material	The emission factor for the utilised materials.

3.2

Common Elements for Quantification

3.2.1

Completeness and Materiality

The quantification of associated GHG emissions shall be complete and cover all process and combustion emissions from all material emission sources and source streams belonging to the permanent carbon removal activities and all other relevant emissions.

Where an Operator or the Certification Body identifies emissions from a source, or from a group of sources, associated with an Activity that are material but are not covered by the present methodology, the Operator shall ensure that such emissions are included in the calculation of the associated GHG emissions.

Unless otherwise stated, all emission sources identified in these rules must be assessed and must be included in the calculation of $GHG_{associated}$ , even if they do not reach the level of Materiality described here.

There are two potential exceptions to this principle, contexts in which a Materiality assessment may be undertaken and emissions assessed as being below the Materiality threshold do not need to be directly assessed. These contexts are capital emissions (Section 3.2.5), and input emissions (Sections 3.1.5.3.2 and 3.1.7.4.2).

A Materiality assessment may also be required, as noted above, if the Operator or the Certification Body identified emissions from a source that is associated with the Activity but is not explicitly identified in the present methodology. Where a Materiality assessment is required on a specified emission source or group of emission sources, the Operator must present to the Certification Body an estimate of the potential range of emissions across the Activity Period associated with that source. If the emissions at the high end of this range are equal to or greater than 1 % of the Net Removals delivered, or expected to be delivered, over the course of the Activity Period, then the emissions from that source are considered potentially material and must be directly assessed.

At the Certification Audit, Operators shall carry out the Materiality assessment based on expected emissions and removals over the Activity Period, and the basis for concluding that any emissions are immaterial shall be described in the Activity Plan.

At the Re-Certification Audit the Certification Body shall assess whether there has been a significant deviation from the operational conditions declared at the Certification Audit. If such a deviation is identified Operators shall carry out the Materiality assessment again.

3.2.2

Net Consumption of Useful Heat or Electricity

Any energy recovery resulting from process configurations may lead to a reduction in the additional net consumption of a specified type of energy or a shift in net demand from one energy type to another. Therefore, for the calculation of net electricity or net useful heat consumption, Operators shall assess the overall change in demand after such recovery processes have been implemented.

The calculation of net consumption shall exclude any electricity or heat both produced and consumed on-site at the capture facility or the storage site or for the transport infrastructure. Emissions associated with electricity or heat generated on-site at a facility shall be accounted for separately by consideration of the fuel consumed. The overall change in demand corresponds to the difference between the quantity of electricity or heat imported from outside the facility for use directly by the Activity and the quantity of electricity or heat that is exported for other uses that was recovered from processes directly required for the Activity, including downstream processes such as CO₂ liquefaction. The calculation of net electricity or net useful heat consumption shall not include any heat or electricity that is produced specifically for export from the facility rather than recovered from a necessary process. Where the net quantity of consumed heat or electricity is less than the gross quantity and this heat or electricity originates from more than one source, $Q_{heat/elec,net,source}$ , the net consumption from each source shall be calculated proportionally so that:

 $Q_{heat/elec,net,source} = Q_{heat/elec,gross,source} \cdot \frac{\sum_{sources} Q_{heat/elec,net,source}}{\sum_{sources} Q_{heat/elec,gross,source}}$

(Equation 69)

Where:

$Q_{heat/elec,gross,source}$ = the gross quantity of electricity or useful heat from a given source consumed in the Certification Period;
$Sources$ = the index of sources of heat or electricity.

In the case of a net increase in availability of a type of energy as a result of energy recovery, the quantity ( $Q_{heat}$ or $Q_{elec}$ ) may be reported as a negative value. Operators shall ensure that any above-mentioned negative quantity is substantiated through correct process assumptions. In the case that one or both of the terms $Q_{heat}$ or $Q_{elec}$ calculated for a process element is negative, then the accompanying emission factor ( $EF_{heat}$ or $EF_{elec}$ ) shall be set to zero (i.e., there shall never be a negative term for $GHG_{heat}$ or $GHG_{elec}$ ).

3.2.3

Additional Biomass Consumption

Additional biomass consumption refers to the biomass, biofuel, bioliquid and biomass fuel that is consumed specifically to provide energy for a carbon capture process. In the case that heat is recovered from an existing biomass-based process whose primary aim is not the production of heat or electricity, and is used by the capture facility, this shall not be treated as a form of additional biomass consumption and shall instead be assessed using an emission factor for the consumed heat following Section 3.2.4.3.

3.2.3.1

Bioenergy Facilities Generating Only Electricity

In the case that carbon is captured at a bioenergy facility generating only electricity and some of this own electricity is consumed to power the carbon capture process, the additional biomass consumption, $Q_{biomass}$ shall be calculated from the net amount of own electricity consumed in accordance with Equation 70.

 $Q_{biomass} = \frac{Q_{elec}}{\eta_{elec}}$

(Equation 70)

Where:

$Q_{elec}$ = the net consumption of own electricity;
$\eta_{elec}$ = the electrical efficiency of the facility, defined as the electricity produced in the Certification Period, including the electricity consumed for carbon capture, divided by the fuel input in the Certification Period based on its energy content.

3.2.3.2

Bioenergy Facilities Generating Only Heat

In the case that carbon is being captured at a bioenergy facility generating only heat and some of this own heat is consumed to power the carbon capture process, the additional biomass consumption $Q_{biomass}$ shall be calculated from the net amount of own heat consumed in accordance with Equation 71.

 $Q_{biomass} = \frac{Q_{heat}}{\eta_{heat}}$

(Equation 71)

Where:

$Q_{heat}$ = the net consumption of own heat;
$\eta_{heat}$ = the heat efficiency of the facility, defined as the heat produced in the Certification Period, including the heat consumed for carbon capture, divided by the fuel input in the Certification Period based on its energy content.

3.2.3.3

Bioenergy Facilities Generating a Mix of Heat and Electricity

In the case that carbon is captured at a bioenergy facility generating both electricity and heat, the additional biomass consumption $Q_{biomass}$ shall be calculated from the net amount of own electricity and own heat consumed in accordance with Equation 72, whereby the value of $Q_{biomass}$ shall be >0.

 $Q_{biomass} = \frac{C_{elec} \cdot Q_{elec} + C_{heat} \cdot Q_{heat}}{C_{elec} \cdot \eta_{elec} + C_{heat} \cdot \eta_{heat}}$

(Equation 72)

Where:

$Q_{elec}$ = the net consumption of own electricity;
$\eta_{elec}$ = the electrical efficiency of the facility, defined as the electricity produced in the Certification Period, including the electricity consumed for carbon capture, divided by the fuel input in the Certification Period based on its energy content;
$Q_{heat}$ = the net consumption of own heat;
$\eta_{heat}$ = the heat efficiency of the facility, defined as the heat produced in the Certification Period, including the heat consumed for carbon capture, divided by the fuel input in the Certification Period based on its energy content;
$C_{elec}$ = the fraction of exergy in the electricity, set to 1;
$C_{heat}$ = the carnot efficiency (fraction of exergy in useful heat), defined as $C_{heat} = \frac{T_{heat}-T_0}{T_{heat}}$ where $T_{heat}$ is the average temperature of the consumed heat in K (Kelvin), and $T_0$ is 273.15 K.

The two parameters $\eta_{elec}$ and $\eta_{heat}$ must be set consistently, either both by calculation or both by reference to technical documentation. If the values are based on technical documentation then they must be set on the same basis as if they were calculated (i.e., expected electricity and heat output, respectively, divided by expected fuel consumption in a representative mode of operation) and the Certification Body shall verify that the values used are consistently achievable under nominal operation of the facility, and that the mode of operation used to set the values is a reasonable representation of the way in which the installation is actually operated.

3.2.4

Emission Factors

3.2.4.1

Electricity

The emission factor applied in the calculation of emissions associated with any net electricity consumption ( $EF_{elec}$ ) shall be calculated in accordance with paragraphs 5 and 6 of Part A of the Annex to Commission Delegated Regulation (EU) 2023/1185.

By way of derogation from the first paragraph:

the calculation period for the electricity emissions factor may be less than a calendar year and may span across parts of two calendar years. The Certification Period includes only part of one or two calendar years:
if the Certification Period falls entirely within a single calendar year, the electricity emission factor shall be calculated either based on data for the exact Certification Period or on data for the full calendar year;
if the Certification Period spans across two calendar years, an electricity emission factor shall be calculated for electricity consumed in each of those calendar years either based on data for the exact part of the Certification Period falling in each year or on data for the full calendar years.
for any Activity based on a new capture facility for which a final investment decision is made and construction has started no later than 31 December 2029, and for which the Operator claims a zero emission factor for consumed electricity on the basis that the electricity is fully renewable, then if the Operator is required to demonstrate temporal correlation between the consumption and generation of the renewable electricity that temporal correlation may be assessed on an annual basis instead of on an hourly basis until 31 December 2044 or the end of the first Activity Period, whichever is sooner.

Operators may choose the approach to attribute greenhouse gas emissions values to the electricity for each source of consumed electricity independently, i.e. they are not required to use the same approach for setting the emission factor for electricity consumed in different locations.

Isometric may provide lists of up to date electricity emissions intensity values at the bidding zone level. In the case of net electricity export (a negative value for $Q_{elec}$ ) the emission factor shall be zero.

Paragraphs 5 and 6 of Part A of the Annex to Commission Delegated Regulation (EU) 2023/1185

Paragraph 5 Part A of the Annex : Electricity qualifying as fully renewable according to Article 27(3) of Directive (EU) 2018/2001, must be attributed zero greenhouse gas emissions.Paragraph 6 Part A of the Annex: One of the three following alternative methods must be applied during each calendar year to attribute greenhouse gas emissions values to the electricity taken from the grid that does not qualify as fully renewable according to Article 27(3) of Directive (EU) 2018/2001 and is used to produce renewable liquid and gaseous transport fuels of non-biological origin and recycled carbon fuels:(a)greenhouse gas emissions values must be attributed according to part C of this Annex. This is without prejudice to the assessment under State aid rules;(b)greenhouse gas emissions values must be attributed depending on the number of full load hours the installation producing renewable liquid and gaseous transport fuels of non-biological origin and recycled carbon fuels is operating. Where the number of full load hours is equal or lower than the number of hours in which the marginal price of electricity was set by installations producing renewable electricity or nuclear power plants in the preceding calendar year for which reliable data are available, grid electricity used in the production process of renewable liquid and gaseous transport fuels of non-biological origin and recycled carbon fuels must be attributed a greenhouse gas emissions value of zero gCO₂eq/MJ. Where this number of full load hours is exceeded, grid electricity used in the production process of renewable liquid and gaseous transport fuels of non-biological origin and recycled carbon fuels must be attributed a greenhouse gas emissions value of 183 gCO₂eq/MJ; or(c)the greenhouse gas emissions value of the marginal unit generating electricity at the time of the production of the renewable liquid and gaseous transport fuels of non-biological origin in the bidding zone may be used if this information is publicly available from the national transmission system Project Proponent.If the method set in point (b) is used, it must also be applied to electricity that is used to produce renewable liquid and gaseous transport fuels of non-biological origin and recycled carbon fuels and qualifies as fully renewable according to Article 27(3) of Directive (EU) 2018/2001, Article 27(3) - Calculation rules with regard to the minimum shares of renewable energy in the transport sector.

3.2.4.2

Heat

The following emission factors shall be applied in the calculation of emissions associated with any net heat consumption:

for heat that is recovered from a process that is part of the Activity: there are no additional emissions;
for heat that is generated by combustion of fossil fuels: lifecycle emission factors for fossil fuel supply and combustion set out in the latest version of the Joint Research Centre document Definition of input data to assess GHG default emissions from biofuels in EU legislation divided by the thermal efficiency of the heat generation process;
for heat that is generated from biomass, biofuel, bioliquid or biomass fuel other than the case of own-heat consumption by a facility capturing CO₂ from biomass consumption for energy generation: emission factors for the supply and combustion (excluding CO₂ from combustion) of the biomass, biofuel, bioliquid or biomass fuel used, calculated in accordance with Annex VI to Directive (EU) 2018/2001 divided by the thermal efficiency of the heat generation process;
for heat that is generated from non-biomass renewable sources: the emission factor is equal to zero;
for heat from nuclear energy production: the emission factor is equal to zero;
for heat that is recovered from a process from which heat was not previously recovered until a maximum of three months prior to the start of the Activity): emission factor is equal to zero;
for heat that is recovered from a process from which heat was already recovered or from a new process, i.e., a process coming into operation less than 6 months prior to the start of the Activity, and that process is not directly related to the Activity: the emission factor shall be set to the EU ETS benchmark emission factor for heat;
for heat that is supplied from a heat network: the emission factor shall be set to the EU ETS benchmark emission factor for heat.

In the case of net heat export (a negative value for $Q_{heat}$ ) the emission factor will be zero.

3.2.4.3

Biomass

When biomass, biofuel, bioliquid or biomass fuel meeting the sustainability requirements set out in Article 29 of Directive (EU) 2018/2001**** is consumed for an Activity (see Section 3.1.5.3.1), any CO₂ produced by chemical processes from the carbon atoms therein contained shall be accounted for with a CO₂ emission factor equal to zero, but the supply chain emissions for provision of the biomass, biofuel, bioliquid or biomass fuel shall be accounted for, and any non-CO₂ emissions associated with biomass combustion (primarily CH₄ and N₂O) shall be accounted for.

The emission factor applied in the calculation of supply chain emissions associated with any consumption of biomass, biofuel, bioliquid or biomass fuel for the Activity shall be calculated in accordance with the rules for calculating the GHG emissions associated with biomass, biofuel, bioliquid or biomass fuel supply set out in Annex V and Annex VI to Directive (EU) 2018/2001, considering the emissions up to the point of consumption associated with the terms $e_{ec}$ , $e_l$ and $e_p$ as defined in those requirements, plus emissions associated with transport (see next paragraph), and converting where necessary from emissions per unit of energy produced by a bioenergy facility to emissions per unit of feedstock consumed. As in Directive (EU) 2018/2001, wastes and residues shall be considered to have zero life-cycle greenhouse gas emissions up to the process of collection of those materials. For municipal waste, post-consumer wood waste and sewage sludge the ‘process of collection’ for the purposes of emissions calculation under Regulation (EU) 2024/3012 shall be understood to start only when the material is deposited at the facility at which the CO₂ capture Activity will be implemented (for example at an energy recovery facility).

Emissions for transport of the biomass, biofuel, bioliquid or biomass fuel to the capture facility shall be calculated based on the actual distance travelled and mode of transport, whereby the disaggregated default emission factors listed for the $e_{td}$ term shall not be used. With regard to indirect land-use change (ILUC) emissions, the requirements set in Section 5.3.1. prevent the increase in the consumption of food and feed crops or food and feed-crop based biofuels, bioliquids or biomass fuels to supply on-site heat or electricity used for the CO₂ capture process and therefore ILUC emissions shall be set to zero.

Isometric may provide guidance on the calculation for feedstocks that do not have disaggregated default values in the Annexes to Directive (EU) 2018/2001.

Article 29 to Directive (EU) 2018/2001

Article 29 Sustainability and greenhouse gas emissions saving criteria for biofuels, bioliquids and biomass fuels1. energy from biofuels, bioliquids and biomass fuels must be taken into account for the purposes referred to in points (a), (b) and (c) of this subparagraph only if they fulfil the sustainability and the greenhouse gas emissions saving criteria laid down in paragraphs 2 to 7 and 10:(a) contributing towards the Union target set in Article 3(1) and the renewable energy shares of Member States;(b) measuring compliance with renewable energy obligations, including the obligation laid down in Article 25;(c) eligibility for financial support for the consumption of biofuels, bioliquids and biomass fuels.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 greenhouse gas emissions saving criteria laid down in paragraph 10 in order to be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph. This subparagraph must 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 must not be subject to the greenhouse gas emissions saving criteria laid down in paragraph 10.Biomass fuels must fulfil the sustainability and greenhouse gas emissions saving criteria laid down in paragraphs 2 to 7 and 10 if used in installations producing electricity, heating and cooling or fuels with a total rated thermal input equal to or exceeding 20 MW in the case of solid biomass fuels, and with a total rated thermal input equal to or exceeding 2 MW in the case of gaseous biomass fuels. Member States may apply the sustainability and greenhouse gas emissions saving criteria to installations with lower total rated thermal input.The sustainability and the greenhouse gas emissions saving criteria laid down in paragraphs 2 to 7 and 10 must apply irrespective of the geographical origin of the biomass.2. biofuels, bioliquids and biomass fuels produced from waste and residues derived not from forestry but from agricultural land must be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 only where Project Proponents or national authorities have monitoring or management plans in place in order to address the impacts on soil quality and soil carbon. Information about how those impacts are monitored and managed must be reported pursuant to Article 30(3); 3. biofuels, bioliquids and biomass fuels produced from agricultural biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 must not be made from raw material obtained from land with a high biodiversity value, namely land that had one of the following statuses in or after January 2008, whether or not the land continues to have that status:(a) primary forest and other wooded land, namely forest and other wooded land of native species, where there is no clearly visible indication of human activity and the ecological processes are not significantly disturbed;(b) highly biodiverse forest and other wooded land which is species-rich and not degraded, or has been identified as being highly biodiverse by the relevant competent authority, unless evidence is provided that the production of that raw material did not interfere with those nature protection purposes;(c) areas designated:(i) by law or by the relevant competent authority for nature protection purposes; or(ii) for the protection of rare, threatened or endangered ecosystems or species recognised by international agreements or included in lists drawn up by intergovernmental organisations or the International Union for the Conservation of Nature, subject to their recognition in accordance with the first subparagraph of Article 30(4),unless evidence is provided that the production of that raw material did not interfere with those nature protection purposes;(d) highly biodiverse grassland spanning more than one hectare that is:(i) natural, namely grassland that would remain grassland in the absence of human intervention and that maintains the natural species composition and ecological characteristics and processes; or(ii) non-natural, namely grassland that would cease to be grassland in the absence of human intervention and that is species-rich and not degraded and has been identified as being highly biodiverse by the relevant competent authority, unless evidence is provided that the harvesting of the raw material is necessary to preserve its status as highly biodiverse grassland.The Commission may adopt implementing acts further specifying the criteria by which to determine which grassland are to be covered by point (d) of the first subparagraph of this paragraph. Those implementing acts must be adopted in accordance with the examination procedure referred to in Article 34(3).4. biofuels, bioliquids and biomass fuels produced from agricultural biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 must not be made from raw material obtained from land with high-carbon stock, namely land that had one of the following statuses in January 2008 and no longer has that status:(a) wetlands, namely land that is covered with or saturated by water permanently or for a significant part of the year;(b) continuously forested areas, namely land spanning more than one hectare with trees higher than five metres and a canopy cover of more than 30 %, or trees able to reach those thresholds in situ;(c) land spanning more than one hectare with trees higher than five metres and a canopy cover of between 10 % and 30 %, or trees able to reach those thresholds in situ, unless evidence is provided that the carbon stock of the area before and after conversion is such that, when the methodology laid down in Part C of Annex V is applied, the conditions laid down in paragraph 10 of this Article would be fulfilled.This paragraph must not apply if, at the time the raw material was obtained, the land had the same status as it had in January 2008.5. biofuels, bioliquids and biomass fuels produced from agricultural biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 must not be made from raw material obtained from land that was peatland in January 2008, unless evidence is provided that the cultivation and harvesting of that raw material does not involve drainage of previously undrained soil; 6. biofuels, bioliquids and biomass fuels produced from forest biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 must meet the following criteria to minimise the risk of using forest biomass derived from unsustainable production:(a) the country in which forest biomass was harvested has national or sub-national laws applicable in the area of harvest as well as monitoring and enforcement systems in place ensuring:(i) the legality of harvesting operations;(ii) forest regeneration of harvested areas;(iii) that areas designated by international or national law or by the relevant competent authority for nature protection purposes, including in wetlands and peatlands, are protected;(iv) that harvesting is carried out considering maintenance of soil quality and biodiversity with the aim of minimising negative impacts; and(v) that harvesting maintains or improves the long-term production capacity of the forest;(b) when evidence referred to in point (a) of this paragraph is not available, the biofuels, bioliquids and biomass fuels produced from forest biomass must be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 if management systems are in place at forest sourcing area level ensuring:(i) the legality of harvesting operations;(ii) forest regeneration of harvested areas;(iii) that areas designated by international or national law or by the relevant competent authority for nature protection purposes, including in wetlands and peatlands, are protected unless evidence is provided that the harvesting of that raw material does not interfere with those nature protection purposes;(iv) that harvesting is carried out considering the maintenance of soil quality and biodiversity with the aim of minimising negative impacts; and(v) that harvesting maintains or improves the long-term production capacity of the forest.7. biofuels, bioliquids and biomass fuels produced from forest biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 must meet the following land-use, land-use change and forestry (LULUCF) criteria:(a) the country or regional economic integration organisation of origin of the forest biomass:(i) is a Party to the Paris Agreement;(ii) has submitted a nationally determined contribution (NDC) to the United Nations Framework Convention on Climate Change (UNFCCC), covering emissions and removals from agriculture, forestry and land use which ensures that changes in carbon stock associated with biomass harvest are accounted towards the country's commitment to reduce or limit greenhouse gas emissions as specified in the NDC; or(iii) has national or sub-national laws in place, in accordance with Article 5 of the Paris Agreement, applicable in the area of harvest, to conserve and enhance carbon stocks and sinks, and providing evidence that reported LULUCF-sector emissions do not exceed removals;(b) where evidence referred to in point (a) of this paragraph is not available, the biofuels, bioliquids and biomass fuels produced from forest biomass must be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 if management systems are in place at forest sourcing area level to ensure that carbon stocks and sinks levels in the forest are maintained, or strengthened over the long term.8. by 31 January 2021, the Commission must adopt implementing acts establishing the operational guidance on the evidence for demonstrating compliance with the criteria laid down in paragraphs 6 and 7 of this Article. Those implementing acts must be adopted in accordance with the examination procedure referred to in Article 34(3); 9. by 31 December 2026, the Commission must assess whether the criteria laid down in paragraphs 6 and 7 effectively minimise the risk of using forest biomass derived from unsustainable production and address LULUCF criteria, on the basis of the available data.The Commission must, if appropriate, submit a legislative proposal to amend the criteria laid down in paragraphs 6 and 7 for the period after 2030.10. the greenhouse gas emission savings from the use of biofuels, bioliquids and biomass fuels taken into account for the purposes referred to in paragraph 1 must be:(a) at least 50 % for biofuels, biogas consumed in the transport sector, and bioliquids produced in installations in operation on or before 5 October 2015;(b) at least 60 % for biofuels, biogas consumed in the transport sector, and bioliquids produced in installations starting operation from 6 October 2015 until 31 December 2020;(c) at least 65 % for biofuels, biogas consumed in the transport sector, and bioliquids produced in installations starting operation from 1 January 2021;(d) at least 70 % for electricity, heating and cooling production from biomass fuels used in installations starting operation from 1 January 2021 until 31 December 2025, and 80 % for installations starting operation from 1 January 2026.An installation must be considered to be in operation once the physical production of biofuels, biogas consumed in the transport sector and bioliquids, and the physical production of heating and cooling and electricity from biomass fuels has started.The greenhouse gas emission savings from the use of biofuels, biogas consumed in the transport sector, bioliquids and biomass fuels used in installations producing heating, cooling and electricity must be calculated in accordance with Article 31(1).11. electricity from biomass fuels must be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 only if it meets one or more of the following requirements:(a) it is produced in installations with a total rated thermal input below 50 MW;(b) for installations with a total rated thermal input from 50 to 100 MW, it is produced applying high-efficiency cogeneration technology, or, for electricity-only installations, meeting an energy efficiency level associated with the best available techniques (BAT-AEELs) as defined in Commission Implementing Decision (EU) 2017/1442 (26);(c) for installations with a total rated thermal input above 100 MW, it is produced applying high-efficiency cogeneration technology, or, for electricity-only installations, achieving an net-electrical efficiency of at least 36 %;(d) it is produced applying Biomass CO₂ Capture and Storage.For the purposes of points (a), (b) and (c) of the first subparagraph of paragraph 1 of this Article, electricity-only-installations must be taken into account only if they do not use fossil fuels as a main fuel and only if there is no cost-effective potential for the application of high-efficiency cogeneration technology according to the assessment in accordance with Article 14 of Directive 2012/27/EU.For the purposes of points (a) and (b) of the first subparagraph of paragraph 1 of this Article, this paragraph must apply only to installations starting operation or converted to the use of biomass fuels after 25 December 2021. For the purposes of point (c) of the first subparagraph of paragraph 1 of this Article, this paragraph must be without prejudice to support granted under support schemes in accordance with Article 4 approved by 25 December 2021.Member States may apply higher energy efficiency requirements than those referred in the first subparagraph to installations with lower rated thermal input.The first subparagraph must not apply to electricity from installations which are the object of a specific notification by a Member State to the Commission based on the duly substantiated existence of risks for the security of supply of electricity. Upon assessment of the notification, the Commission must adopt a decision taking into account the elements included therein.12. for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 of this Article, and without prejudice to Articles 25 and 26, Member States must not refuse to take into account, on other sustainability grounds, biofuels and bioliquids obtained in compliance with this Article. This paragraph must be without prejudice to public support granted under support schemes approved before 24 December 2018; 13. for the purposes referred to in point (c) of the first subparagraph of paragraph 1 of this Article, Member States may derogate, for a limited period of time, from the criteria laid down in paragraphs 2 to 7 and 10 and 11 of this Article by adopting different criteria for:(a) installations located in an outermost region as referred to in Article 349 TFEU to the extent that such facilities produce electricity or heating or cooling from biomass fuels; and(b) biomass fuels used in the installations referred to in point (a) of this subparagraph, irrespective of the place of origin of that biomass, provided that such criteria are objectively justified on the grounds that their aim is to ensure, for that outermost region, a smooth phase-in of the criteria laid down in paragraphs 2 to 7 and 10 and 11 of this Article and thereby incentivise the transition from fossil fuels to sustainable biomass fuels.The different criteria referred to in this paragraph must be subject to a specific notification by the relevant Member State to the Commission.14. for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1, Member States may establish additional sustainability criteria for biomass fuels.By 31 December 2026, the Commission must assess the impact of such additional criteria on the internal market, accompanied, if necessary, by a proposal to ensure harmonisation thereof.

3.2.4.4

Inputs and Fuels

Where the quantification rules require the calculation of emissions associated with the use of inputs to that Activity, including fossil fuels and materials used in the construction of capital equipment, lifecycle emission factors for those inputs shall be taken either from lists of default factors provided by Isometric or from the following hierarchical list of sources, sourcing the emission factors from the first source in the list from which it is available and using, where available, the most recent version of the sources:

part B of the Annex to Delegated Regulation (EU) 2023/1185;
the most recent version of the Environmental Footprint datasets, or EF-compliant datasets;
the Joint Research Centre document, Definition of input data to assess GHG default emissions from biofuels in EU legislation;
the JEC Well-to-Wheels report;
the ECOINVENT database, version 3.5 or a more recent version, or other comparable commercial databases;
official sources such as the Intergovernmental Panel on Climate Change (IPCC), International Energy Agency (IEA), or government;
other reviewed sources or peer-reviewed publications.

Where access to any databases under point (5) is not possible, Operators may rely on points (6) or (7) above.

The lifecycle emission factors shall reflect the emissions associated with supplying those inputs up to the point of use by the Activity. If necessary, emission factors taken from these sources shall be adjusted to exclude any carbon contained within the input material itself. If such carbon is oxidised and emitted as a result of processes associated with the Activity this shall be counted as an emission source directly. The use of data from divergent sources may lead to slight inconsistencies in the scope of lifecycle accounting applied to different inputs. Operators are not required to recalculate data from these sources to achieve full consistency in lifecycle scope across the utilised input data.

Isometric may provide lists of default conservative emission factors. This may include emission factors available from sources in the hierarchical list above. If there is uncertainty in the best estimate of these values or if some degree of variability can be expected in these values, such default emission factors shall be set conservatively, i.e. must be set in such a way that the use of those default emission factors is likely to lead to a marginal underestimation of delivered net carbon removals. Where standard deviation is quoted for a value, the default shall be set to the mean value plus one standard deviation. Where a 95% confidence interval is quoted for a value, the default value shall be set halfway between the mean value and the 95% confidence limit. These adjustments shall always be made in the direction that reduces the estimated net carbon removal benefit for an Activity. Default emission factors shall be treated as having no associated uncertainty in the calculation specified in Section 3.2.6.

part B of the Annex to Delegated Regulation (EU) 2023/1185

The GHG intensities of inputs other than electricity are shown in the table below:

Fuel	Total emissions (gCO₂eq/MJ)	Upstream emissions (gCO₂eq/MJ)	Combustion emissions (gCO₂eq/MJ)
Natural gas	66.0	9.7	56.2
Diesel	95.1	21.9	73.2
Gasoline	93.3	19.9	73.4
Heavy fuel oil	94.2	13.6	80.6
Methanol	97.1	28.2	68.9
Hard coal	112.3	16.2	96.1
Lignite	116.7	1.7	115.0

Material	Emissions (gCO₂eq/kg)
Ammonia	2351.3
Calcium chloride (CaCl₂)	38.8
Cyclohexane	723.0
Hydrochloric acid (HCl)	1061.1
Lubricants	947.0
Magnesium sulphate (MgSO₄)	191.8
Nitrogen	56.4
Phosphoric acid (H₃PO₄)	3124.7
Potassium hydroxide (KOH)	419.1
Pure CaO for processes	1193.2
Sodium carbonate (Na₂CO₃)	1245.1
Sodium chloride (NaCl)	13.3
Sodium hydroxide (NaOH)	529.7
Sodium methoxide (Na(CH₃O))	2425.5
SO₂	53.3
Sulphuric acid (H₂SO₄)	217.5
Urea	1846.6

3.2.4.5

Transport

Emissions from transport, whether of CO₂ or of bulk materials, may be calculated either based on assessment of the fuel consumption and consequent emissions associated with the specific vehicles and routes utilised or based on conservative default factors provided by Isometric. Isometric may provide additional conservative default emission factors for specific forms of CO₂ transport, under the condition that the basis for these values are clearly documented and the values are demonstrated to be conservative.

Where default values are not used, Operators may estimate the emissions either by recording the actual fuel consumption of the vehicles and other infrastructure utilised or by calculating the product of the average GHG emissions associated with operating the specific vehicle or infrastructure (in gCO₂e/km) and the distance travelled. GHG emission factors for fuels consumed shall be set on a lifecycle basis (i.e., including upstream emissions) in accordance with Section 3.2.4.4 GHG emission factors for vehicles transporting CO₂ shall account for the mass of the CO₂ containment equipment and for energy expenditures to compress and liquefy the CO₂ and maintain it in that state. Operators shall account for the emissions associated with the return trip of vehicles used to transport CO₂ or bulk materials considering them empty, unless they demonstrate that the return trip is used to provide another transport service. In that case the return emissions allocated to the Activity may be set at zero for those trips.

3.2.5

Capital Emissions

If the quantification rules require the consideration of capital emissions associated with one or more facilities, the following shall apply:

if any facility first came into operation or has been expanded or refitted within 15 years prior to the certification date of the Activity, or will be expanded or refitted within the Activity Period, the capital emissions associated with that construction, expansion or refit shall be considered;
for any other facility, the capital emissions shall be considered to be zero;
a Materiality assessment shall be undertaken for the sum of all capital emissions across all relevant facilities. If the Certification Body concludes on the basis of this assessment that capital emissions may be material, the capital emissions shall be assessed;
any capital emissions associated with non-biomass renewable energy generating equipment shall be excluded from the calculation;
capital emissions shall only be assessed for the part of facilities or equipment that is directly required for the performance of the Activity (i.e., specifically required for the CO₂ capture and not solely for the underlying Activity from which CO₂ is captured).

If capital emissions are to be assessed, the total capital emissions for each facility or facilities shall be calculated by taking an inventory of the construction materials utilised and fuel and energy consumed in the construction of the facility and summing the associated emissions. Emissions factors used in assessing capital emissions shall consider the full lifecycle of the materials and energy utilised. The calculated capital emissions for each facility shall be amortised by dividing them across either fifteen or twenty years. In cases where not all of the CO₂ handled by the facility is associated with the Activity certified under Regulation (EU) 2024/3012 (e.g., if some of the CO₂ is transferred for utilisation) a pro-rata fraction of the capital emissions shall be allocated to the Activity. In the case that a facility has equal or lower material requirements for construction than a previously constructed facility of the same type, Operators may use the capital emissions for that previous facility as an estimate of capital emissions for the new facility.

Isometric may provide conservative capital emissions factors for specific Activity types, Activity stages or facility sizes as an alternative to undertaking an Activity-specific Materiality assessment or full calculation. Such conservative values shall be set in such a way that they can be reasonably expected to be higher than the actual capital emissions for the relevant facility in at least 95% of cases. If providing a default-based option, Isometric will clearly document the basis for treating the provided values as conservative.

This amortised emission shall be added to the associated GHG emissions for the Activity for each year until either the fifteenth or the twentieth year (depending on the chosen amortisation period) following the year in which the facility came into operation, was expanded or was refitted, as relevant, in accordance with Equation 73.

 $GHG_{capital} = \frac{Q_{activity}}{Q_{total}} \cdot \frac{GHG_{combustion}+GHG_{elec}+GHG_{heat}+GHG_{materials}}{T}$

(Equation 73)

Where:

$T$ = the amortisation period of either 15 or 20 years;
$Q_{activity}$ = the utilisation of the capital equipment by the Activity in a relevant units;
$Q_{total}$ = the expected annual average total utilisation of the capital equipment over its operational lifetime in the same units (so that $\frac{Q_{activity}}{Q_{total}} =1$ if the equipment is used only by the Activity) and, depending on the process step in the carbon removal Activity, $GHG_{combustion}$ shall be calculated as in Equation 39, $GHG_{elec}$ shall be calculated as in Equation 22 or 40, $GHG_{heat}$ shall be calculated as in Equation 23 or 41 and $GHG_{materials}$ shall be calculated in accordance with Equation 74.

 $GHG_{materials} = \sum_{materials} Q_{materials} \cdot EF_{materials}$

(Equation 74)

Where:

$Q_{materials}$ = the quantity of materials utilised in the construction of the facility, expressed in tonnes;
$EF_{materials}$ = the emission factor for the utilised materials, expressed in tCO₂/t of material, selected in accordance with Section 3.2.4.4.

3.2.6

Measured Data and Uncertainties

Measurements, including measurements of CO₂ flows shall be undertaken in a way consistent with the requirements of Article 42 of Implementing Regulation (EU) 2018/2066.

Where measured, estimated or default data are used as the basis for calculations of sources or sinks, the Activity shall assess the uncertainty introduced into the calculation of net carbon removals. Operators shall follow the principles for combining uncertainties set out in Section 3 of Chapter 6 (‘Quantifying Uncertainties in Practice’) of the IPCC document Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories. Uncertainty shall be assessed based on the 95% confidence interval.

If the total resulting uncertainty estimate is lower than ±2.5%, no adjustment shall be applied (i.e., $F_C$ = 1).

Otherwise, the conservatism factor $F_C$ shall be set to 100% minus the total uncertainty estimate.

If the total resulting uncertainty estimate is greater than ±20%, no units will be issued for that Certification Period.

Uncertainty shall be assessed based on a 95% confidence interval.

If the total uncertainty estimate is lower than ±2.5%, no adjustment is applied. Otherwise, the conservatism factor $F_C$ shall be set to 100%.

If the total uncertainty estimate is greater than ±20%, no Credits will be issued for that Certification Period.

Article 42 of Implementing Regulation (EU) 2018/2066

Article 42 Measurement standards and laboratories1. all measurements must be carried out applying methods based on:(a) EN 14181 (Stationary source emissions — Quality assurance of automated measuring systems);(b) EN 15259 (Air quality — Measurement of stationary source emissions — Requirements for measurement sections and sites and for the measurement objective, plan and report);(c) 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 must 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 must be used, limiting sampling and measurement bias.The Project Proponent must consider all relevant aspects of the continuous measurement system, including the location of the equipment, calibration, measurement, quality assurance and quality control.2. the Project Proponent must ensure that laboratories carrying out measurements, calibrations and relevant equipment assessments for CEMS are accredited in accordance with EN ISO/IEC 17025 for the relevant analytical methods or calibration activities.Where the laboratory does not have such accreditation, the Project Proponent must ensure that equivalent requirements of Article 34(2) and (3) are met.

3.2.7

Confirmation of Origin of CO|2| Stream

Confirmation of Origin of CO₂ Stream

For carbon removal activities with CO₂ capture and permanent carbon storage, if the facility at which the CO₂ is captured is not subject to monitoring under the ETS of the biogenic CO₂ amount, the Operators shall provide access, immediately at request, to representatives of Certification Bodies, Isometric or relevant national authorities to allow unannounced random ¹⁴C testing of the CO₂ stream leaving the facility prior to the point of leaving the facility (and if relevant prior to being intermixed with any separately captured fossil CO₂ stream) to confirm its biogenic origin. If the biogenic origin cannot be confirmed then no units may be issued for the corresponding Certification Period, and Isometric must consider whether further action is required.

4.0

Carbon Storage and Liability

4.1

Bio-CCS Activities

The CO₂ captured by the Activity shall be injected at an operational geological storage site permitted under Directive 2009/31/EC and Operators of storage sites used by Bio-CCS activities are liable for any release of CO₂ from permanent geological storage under the rules set out in Article 16 of Directive 2009/31/EC.

Article 16 of Directive 2009/31/EC

Article 16 Measures in case of leakages or significant irregularities1. member States must ensure that in the event of leakages or significant irregularities, the Project Proponent immediately notifies the competent authority, and takes the necessary corrective measures, including measures related to the protection of human health. In cases of leakages and significant irregularities which imply the risk of leakage, the Project Proponent must also notify the competent authority pursuant to Directive 2003/87/EC; 2. the corrective measures referred to in paragraph 1 must be taken as a minimum on the basis of a corrective measures plan submitted to and approved by the competent authority pursuant to Article 7(7) and Article 9(6); 3. the competent authority may at any time require the Project Proponent to take the necessary corrective measures, as well as measures related to the protection of human health. These may be additional to or different from those laid out in the corrective measures plan. The competent authority may also at any time take corrective measures itself; 4. if the Project Proponent fails to take the necessary corrective measures, the competent authority must take the necessary corrective measures itself; 5. the competent authority must recover the costs incurred in relation to the measures referred to in paragraphs 3 and 4 from the Project Proponent, including by drawing on the financial security pursuant to Article 19.

5.0

Sustainability

5.1

Minimum Sustainability Requirements

5.1.1

Climate Change Mitigation

The eligibility requirements listed in Section 2.1 prevent the certification of activities that significantly harm the objective of climate change mitigation.

5.1.2

Climate Change Adaptation

Operators shall comply with the criteria related to climate adaptation set out in Appendix A to Annex 1 to Commission Delegated Regulation (EU) 2021/2139.

Appendix A Commission Delegated Regulation (EU) 2021/2139

Appendix A Classification of Climate-related hazards

	Temperature-related	Wind-related	Water-related	Solid mass-related
Chronic	Changing temperature (air, freshwater, marine water)	Changing wind patterns	Changing precipitation patterns and types (rain, hail, snow/ice)	Coastal erosion
	Heat stress		Precipitation or hydrological variability	Soil degradation
	Temperature variability		Ocean acidification	Soil erosion
	Permafrost thawing		Saline intrusion	Solifluction
			Sea level rise
			Water stress
Acute	Heat wave	Cyclone, hurricane, typhoon	Drought	Avalanche
	Cold wave/frost	Storm (including blizzards, dust and sandstorms)	Heavy precipitation (rain, hail, snow/ice)	Landslide
	Wildfire	Tornado	Flood (coastal, fluvial, pluvial, ground water)	Subsidence
			Glacial lake outburst

5.1.3

Sustainable Use and Protection of Water and Marine Resources

Operators shall evaluate and address any potential risks due to the Activity to the good status or the good ecological potential of bodies of water, including surface water and groundwater, or to the good environmental status of marine waters. In the case that pollutants that are scrubbed from flue gases in order to reduce air pollution may be released to a body of water, the air pollution benefit and the availability of alternative discharge strategies shall be taken into consideration when evaluating the impact on water quality.

5.1.4

Transition to a Circular Economy, Including the Efficient Use of Sustainably Sourced Bio-Based Materials

Operators shall evaluate and address any potential risks to the circular economy objectives from the Activity, by considering the types of potential significant harm as set out in Article 17(1), point (d), of Regulation (EU) 2020/852 of the European Parliament and of the Council.
Operators shall comply with the requirements set in Sections 5.2 and 5.3.

Article 17 of Regulation (EU) 2020/852

Article 17 Significant harm to environmental objectives(d) the circular economy, including waste prevention and recycling, where:(i) that activity leads to significant inefficiencies in the use of materials or in the direct or indirect use of natural resources such as non-renewable energy sources, raw materials, water and land at one or more stages of the life cycle of products, including in terms of durability, reparability, upgradability, reusability or recyclability of products;(ii) that activity leads to a significant increase in the generation, incineration or disposal of waste, with the exception of the incineration of non-recyclable hazardous waste; or(iii) the long-term disposal of waste may cause significant and long-term harm to the environment;

5.1.5

Pollution Prevention and Control

Operators shall evaluate and address any potential risks to generate a significant increase in the emissions of pollutants to air, water or land from the Activity. Where facilities are within the scope of Directive 2010/75/EU of the European Parliament and of the Council they shall comply with all requirements arising from that Directive.

Scope of Directive 2010/75/EU

Article 2 Scope:1. this Directive must apply to the industrial activities giving rise to pollution referred to in Chapters II to VI; 2. this Directive must not apply to research activities, development activities or the testing of new products and processes.

5.1.6

Protection and Restoration of Biodiversity and Ecosystems Including Soil Health, as well as Avoidance of Land Degradation

Operators shall evaluate and address any potential risks to the good condition or resilience of ecosystems or to the conservation status of habitats and species, including those of Union interest or to the achievement of targets or obligations set out in national restoration plans established under Regulation (EU) 2024/1991 of the European Parliament and of the Council, from the Activity.

5.2

Biomass Sustainability

all biomass, biofuel, bioliquid or biomass fuel that is used to generate the CO₂ captured by the Activity and any additional biomass, biofuel, bioliquid or biomass fuel consumed to produce energy for the Activity shall comply with the following requirements:
where Article 29 of Directive (EU) 2018/2001 sets requirements that are to be met in order for biofuels, bioliquids and biomass fuels to be taken into account for the purposes referred to in Article 29(1), points (a), (b) and (c), of that Directive, those requirements will be applied by the Certification Body also to biomass, biofuel, bioliquid or biomass fuel consumed in relation to an Activity that seeks to generate carbon removal units, even if the Activity does not generate renewable energy that is taken into account under Directive (EU) 2018/2001;
operators shall disclose the biomass feedstock or feedstock mix consumed by the Activity, and the biomass feedstock or feedstock mix used to produce consumed biofuels, bioliquids or biomass fuels, disaggregating feedstock to the level required in Directive (EU) 2018/2001 reporting, in national guidance and in relevant industrial standards;
isometric is required to verify that the requirements in Article 29(10) of Directive (EU) 2018/2001 are met only in the case of a capture Activity taking place at a facility producing heat or electricity or a biofuel, bioliquid or biogas, and with regard to the heat, electricity, biofuel, bioliquid or biogas produced;
the biomass, biofuel, bioliquid or biomass fuel is produced from wastes or residues other than agricultural, aquaculture, fisheries and forestry residues, is not subject to the requirements set out in Article 29(2) to (7) of Directive (EU) 2018/2001.

Voluntary schemes approved by the Commission in accordance with Article 30(4) of Directive (EU) 2018/2001 and national schemes recognised by the Commission in accordance with Article 30(6) of Directive (EU) 2018/2001 shall be treated as providing accurate data for the demonstration of compliance with the biomass sustainability requirements for permanent carbon removal activities of this Regulation. Similarly, any other schemes that have been recognised by competent national authorities in the state where the capture facility is located shall be treated as providing accurate data in relation to the demonstration of compliance with these requirements. With regard to facilities regulated under Directive (EU) 2018/2001, periodic assessments of the compliance with sustainability requirements by Member State competent authorities shall not prevent Isometric approving the issuance of units. However, if such assessment subsequently results in any non-conformity with Article 29 of that Directive, the non-conformity shall be notified to the Certification Body.

where the CO₂ captured by the Activity is produced by a process that generates energy that is taken into account under Directive (EU) 2018/2001:.
1. the Certification Body shall verify that the national implementation of Directive (EU) 2018/2001 applies to the entity operating that process, and that the entity operating that process complies with this national implementation;
2. the Certification Body shall verify that the entity operating that process complies with any measures in national implementations of Directive (EU) 2018/2001 that are introduced to ensure that woody biomass is used according to the list of priorities established in Article 3(3) of Directive (EU) 2018/2001, including any derogations introduced by Member States under Article 3(3a) of Directive (EU) 2018/2001, if the entity operating that process benefits from a relevant support scheme for the energy production;
3. the Certification Body shall verify that the entity operating that process does not receive direct financial support from Member States for the use of saw logs, veneer logs, industrial grade roundwood, stumps and roots to produce energy, as set in Article 3(3c) of Directive (EU) 2018/2001.
the biomass, biofuel, bioliquid or biomass fuel from which emitted CO₂ is captured, or from which the biofuel, bioliquid or biomass fuel from which the emitted CO₂ is captured is produced, shall not be identified as being or as being produced from a high indirect land use change-risk feedstock under Directive (EU) 2018/2001.
if biomass is sourced from areas designated by the national competent authority for conservation, including areas covered by the national restoration plan pursuant to Regulation (EU) 2024/1991, or in habitats that are protected, the sourcing shall be in accordance with the conservation and restoration objectives for those areas.

Article 29(1)(a),(b),(c) of Directive (EU) 2018/2001

energy from biofuels, bioliquids and biomass fuels shall be taken into account for the purposes referred to in points (a), (b) and (c) of this subparagraph only if they fulfil the sustainability and the greenhouse gas emissions saving criteria laid down in paragraphs 2 to 7 and 10:(a) contributing towards the Union target set in Article 3(1) and the renewable energy shares of Member States;(b) measuring compliance with renewable energy obligations, including the obligation laid down in Article 25;(c) eligibility for financial support for the consumption of biofuels, bioliquids and biomass fuels.

Article 29(10) of Directive (EU) 2018/2001

the greenhouse gas emission savings from the use of biofuels, bioliquids and biomass fuels taken into account for the purposes referred to in paragraph 1 shall be:(a) at least 50 % for biofuels, biogas consumed in the transport sector, and bioliquids produced in installations in operation on or before 5 October 2015;(b) at least 60 % for biofuels, biogas consumed in the transport sector, and bioliquids produced in installations starting operation from 6 October 2015 until 31 December 2020;(c) at least 65 % for biofuels, biogas consumed in the transport sector, and bioliquids produced in installations starting operation from 1 January 2021;(d) at least 70 % for electricity, heating and cooling production from biomass fuels used in installations starting operation from 1 January 2021 until 31 December 2025, and 80 % for installations starting operation from 1 January 2026.An installation shall be considered to be in operation once the physical production of biofuels, biogas consumed in the transport sector and bioliquids, and the physical production of heating and cooling and electricity from biomass fuels has started.The greenhouse gas emission savings from the use of biofuels, biogas consumed in the transport sector, bioliquids and biomass fuels used in installations producing heating, cooling and electricity shall be calculated in accordance with Article 31(1).

Article 29(2) to (7) of Directive (EU) 2018/2001

biofuels, bioliquids and biomass fuels produced from waste and residues derived not from forestry but from agricultural land shall be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 only where Project Proponents or national authorities have monitoring or management plans in place in order to address the impacts on soil quality and soil carbon. Information about how those impacts are monitored and managed shall be reported pursuant to Article 30(3);
biofuels, bioliquids and biomass fuels produced from agricultural biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 shall not be made from raw material obtained from land with a high biodiversity value, namely land that had one of the following statuses in or after January 2008, whether or not the land continues to have that status:(a) primary forest and other wooded land, namely forest and other wooded land of native species, where there is no clearly visible indication of human activity and the ecological processes are not significantly disturbed;(b) highly biodiverse forest and other wooded land which is species-rich and not degraded, or has been identified as being highly biodiverse by the relevant competent authority, unless evidence is provided that the production of that raw material did not interfere with those nature protection purposes;(c) areas designated:(i) by law or by the relevant competent authority for nature protection purposes; or(ii) for the protection of rare, threatened or endangered ecosystems or species recognised by international agreements or included in lists drawn up by intergovernmental organisations or the International Union for the Conservation of Nature, subject to their recognition in accordance with the first subparagraph of Article 30(4),unless evidence is provided that the production of that raw material did not interfere with those nature protection purposes;(d) highly biodiverse grassland spanning more than one hectare that is:(i) natural, namely grassland that would remain grassland in the absence of human intervention and that maintains the natural species composition and ecological characteristics and processes; or(ii) non-natural, namely grassland that would cease to be grassland in the absence of human intervention and that is species-rich and not degraded and has been identified as being highly biodiverse by the relevant competent authority, unless evidence is provided that the harvesting of the raw material is necessary to preserve its status as highly biodiverse grassland.The Commission may adopt implementing acts further specifying the criteria by which to determine which grassland are to be covered by point (d) of the first subparagraph of this paragraph. Those implementing acts shall be adopted in accordance with the examination procedure referred to in Article 34(3).4. biofuels, bioliquids and biomass fuels produced from agricultural biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 shall not be made from raw material obtained from land with high-carbon stock, namely land that had one of the following statuses in January 2008 and no longer has that status:(a) wetlands, namely land that is covered with or saturated by water permanently or for a significant part of the year;(b) continuously forested areas, namely land spanning more than one hectare with trees higher than five metres and a canopy cover of more than 30 %, or trees able to reach those thresholds in situ;(c) land spanning more than one hectare with trees higher than five metres and a canopy cover of between 10 % and 30 %, or trees able to reach those thresholds in situ, unless evidence is provided that the carbon stock of the area before and after conversion is such that, when the methodology laid down in Part C of Annex V is applied, the conditions laid down in paragraph 10 of this Article would be fulfilled.This paragraph shall not apply if, at the time the raw material was obtained, the land had the same status as it had in January 2008.5. biofuels, bioliquids and biomass fuels produced from agricultural biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 shall not be made from raw material obtained from land that was peatland in January 2008, unless evidence is provided that the cultivation and harvesting of that raw material does not involve drainage of previously undrained soil;
biofuels, bioliquids and biomass fuels produced from forest biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 shall meet the following criteria to minimise the risk of using forest biomass derived from unsustainable production:(a) the country in which forest biomass was harvested has national or sub-national laws applicable in the area of harvest as well as monitoring and enforcement systems in place ensuring:(i) the legality of harvesting operations;(ii) forest regeneration of harvested areas;(iii) that areas designated by international or national law or by the relevant competent authority for nature protection purposes, including in wetlands and peatlands, are protected;(iv) that harvesting is carried out considering maintenance of soil quality and biodiversity with the aim of minimising negative impacts; and(v) that harvesting maintains or improves the long-term production capacity of the forest;(b) when evidence referred to in point (a) of this paragraph is not available, the biofuels, bioliquids and biomass fuels produced from forest biomass shall be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 if management systems are in place at forest sourcing area level ensuring:(i) the legality of harvesting operations;(ii) forest regeneration of harvested areas;(iii) that areas designated by international or national law or by the relevant competent authority for nature protection purposes, including in wetlands and peatlands, are protected unless evidence is provided that the harvesting of that raw material does not interfere with those nature protection purposes;(iv) that harvesting is carried out considering the maintenance of soil quality and biodiversity with the aim of minimising negative impacts; and(v) that harvesting maintains or improves the long-term production capacity of the forest.7. biofuels, bioliquids and biomass fuels produced from forest biomass taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 shall meet the following land-use, land-use change and forestry (LULUCF) criteria:(a) the country or regional economic integration organisation of origin of the forest biomass:(i) is a Party to the Paris Agreement;(ii) has submitted a nationally determined contribution (NDC) to the United Nations Framework Convention on Climate Change (UNFCCC), covering emissions and removals from agriculture, forestry and land use which ensures that changes in carbon stock associated with biomass harvest are accounted towards the country's commitment to reduce or limit greenhouse gas emissions as specified in the NDC; or(iii) has national or sub-national laws in place, in accordance with Article 5 of the Paris Agreement, applicable in the area of harvest, to conserve and enhance carbon stocks and sinks, and providing evidence that reported LULUCF-sector emissions do not exceed removals;(b) where evidence referred to in point (a) of this paragraph is not available, the biofuels, bioliquids and biomass fuels produced from forest biomass shall be taken into account for the purposes referred to in points (a), (b) and (c) of the first subparagraph of paragraph 1 if management systems are in place at forest sourcing area level to ensure that carbon stocks and sinks levels in the forest are maintained, or strengthened over the long term.

Article 30(4) and (6) of Directive (EU) 2018/2001

the Commission may decide that voluntary national or international schemes setting standards for the production of biofuels, bioliquids or biomass fuels, or other fuels that are eligible for counting towards the numerator referred to in point (b) of Article 27(1), provide accurate data on greenhouse gas emission savings for the purposes of Article 25(2) and Article 29(10), demonstrate compliance with Article 27(3) and Article 28(2) and (4), or demonstrate that consignments of biofuels, bioliquids or biomass fuels comply with the sustainability criteria laid down in Article 29(2) to (7). When demonstrating that the criteria laid down in Article 29(6) and (7) are met, the Project Proponents may provide the required evidence directly at sourcing area level. The Commission may recognise areas for the protection of rare, threatened or endangered ecosystems or species recognised by international agreements or included in lists drawn up by intergovernmental organisations or the International Union for the Conservation of Nature for the purposes of point (c)(ii) of the first subparagraph of Article 29(3).The Commission may decide that those schemes contain accurate information on measures taken for soil, water and air protection, for the restoration of degraded land, for the avoidance of excessive water consumption in areas where water is scarce, and for certification of biofuels, bioliquids and biomass fuels with low indirect land-use change-risk.6. member States may set up national schemes where compliance with the sustainability and greenhouse gas emissions saving criteria laid down in Article 29(2) to (7) and (10) and with the greenhouse gas emissions savings thresholds for renewable liquid and gaseous transport fuels of non-biological origin and recycled carbon fuels set in, and adopted pursuant to, Article 25(2) and in accordance with Article 28(5) is verified throughout the entire chain of custody involving competent national authorities.A Member State may notify such a national scheme to the Commission. The Commission shall give priority to the assessment of such a scheme in order to facilitate mutual bilateral and multilateral recognition of schemes for verification of compliance with the sustainability and greenhouse gas emissions saving criteria for biofuels, bioliquids and biomass fuels and with the greenhouse gas emissions savings thresholds for other fuels that are eligible for counting towards the numerator referred to in point (b) of Article 27(1). The Commission may decide, by means of implementing acts, whether such a notified national scheme complies with the conditions laid down in this Directive. Those implementing acts shall be adopted in accordance with the examination procedure referred to in Article 34(3).Where the decision is positive, schemes established in accordance with this Article shall not refuse mutual recognition with that Member State's scheme, as regards verification of compliance with the sustainability and greenhouse gas emissions saving criteria laid down in Article 29(2) to (7) and (10) and the greenhouse gas emissions savings thresholds set in, and adopted pursuant to, Article 25(2).

Article 3(3) of Directive (EU) 2018/2001

Member States shall ensure that their national policies, including the obligations deriving from Articles 25 to 28 of this Directive, and their support schemes, are designed with due regard to the waste hierarchy as set out in Article 4 of Directive 2008/98/EC to aim to avoid undue distortive effects on the raw material markets. Member States shall grant no support for renewable energy produced from the incineration of waste if the separate collection obligations laid down in that Directive have not been complied with.

Article 2, point (23) of Directive (EU) 2018/2001

(23)‘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;(43)‘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;

5.3

Avoidance of Unsustainable Demand for Biomass Raw Material

5.3.1

Requirements for Bio-CCS

Any biomass, biofuel, bioliquid or biomass fuel from which CO₂ emitted is captured shall be consumed with the primary purpose of generating a product other than CO₂ for capture, and the process shall not be adjusted in a way that increases the generation of CO₂ per unit of output if that adjustment is made solely to increase the quantity of CO₂ that is available to be captured. This shall not be understood to preclude adjustments made to increase the fraction of the facility’s output that can be made subject to CO₂ capture – for example if a facility has two combustion units one of which has a carbon capture unit, the facility may seek to maximise the use of the unit with carbon capture even if this marginally reduces the overall thermal efficiency of the facility – or to increase the overall efficiency of a production system.

In order to ensure the avoidance of unsustainable demand for biomass raw material, the following additional requirements apply to facilities where the primary purpose of biomass, biofuel, bioliquid or biomass fuel consumption is to produce heat or electricity:

where the facility generating heat or electricity is a newly-constructed facility that became operational not more than one year before the start of the Activity Period, or a facility that previously consumed fossil fuel feedstock, either partly or entirely and that was adjusted to increase the share of biomass, biofuel, bioliquid or biomass fuel in the feedstock mix no more than one year before the start of the Activity Period, Operators shall demonstrate that the facility would still be economically viable without the carbon removal Activity, (i.e., that the net present value would be positive for a version of the facility without the cost of carbon capture or the revenue from carbon removal units or any other support predicated on the delivery of carbon removals);
in all other cases, the Operator shall demonstrate that the nameplate energy generation capacity of the facility has not increased by more than the amount necessary to supply energy for the capture process, as compared to the nameplate capacity on whichever date is later out of the date on which the facility became operational and the date three years prior to the start of the Activity Period.

These requirements do not apply to waste-to-energy facilities combusting wastes or residues other than agricultural, aquaculture, fisheries and forestry residues, nor to facilities using biomass, biofuel, bioliquid or biomass fuel for non-energy applications or for energy applications where heat and or electricity are not the primary outputs (e.g. biofuel or biogas production), nor to facilities where biomass, biofuel, bioliquid or biomass fuel is used as part of a chemical reaction in an industrial process aimed at producing a product other than heat or electricity, even if energy is also extracted from the biomass, biofuel, bioliquid or biomass fuel in this process.

Where the feedstock processed at the installation from which CO₂ is captured includes food and feed crops or food and feed crop-based biofuels, bioliquids or biomass fuels, it is not permissible for energy derived from that feedstock to be used to operate the capture process, excepting the case of recovered heat.

5.3.2

Voluntary Compensation of Biomass Used by Carbon Removal Activities

To support the regeneration of natural carbon stocks used for the generation of permanent carbon removals, Operators of carbon removal activities that are based on consumption of biomass feedstock may purchase carbon farming sequestration units.

The quantity of carbon farming sequestration units purchased by the Operator shall be reported in the certificate of compliance.

6.0

Isometric CRCF Requirements

The following Modules contain Isometric additional requirements above and beyond the CRCF framework to ensure Isometric CRCF Credits are of equivalent quality to Isometric non-CRCF Credits.
For the avoidance of doubt, Isometric additional modules can only ever institute additional checks or subtract from the CRCF equation terms, and never result in a higher credit total.

The additional requirements relating to Bio-CCS Activities that must be overlaid to ensure Credits are of equivalent quality to Isometric's non-CRCF Credits.

The additional requirements relating to GHG accounting that must be overlaid to ensure Credits are of equivalent quality to Isometric's non-CRCF Credits.

The additional requirements relating to the subsurface storage of CO₂ that must be overlaid to ensure Credits are of equivalent quality to Isometric's non-CRCF Credits.

Projects must use one of the following Biomass Feedstock Accounting Modules:

The additional requirements relating to feedstock sourcing that must be overlaid to ensure Credits are of equivalent quality to Isometric's non-CRCF Credits.

The additional requirements relating to feedstock sourcing that must be overlaid to ensure Credits are of equivalent quality to Isometric's non-CRCF Credits only for bioenergy retrofit/additive Activities that provide energy for the capture facility using changes in energy export, grid import or on-site external power generation.

7.0

Isometric CRCF Glossary

This glossary provides a side-by-side comparison of terminology used in the EU Carbon Removal Certification Framework (CRCF) and Isometric Protocols and Module.

8.0

Appendix 1 - CRCF Definitions

For the purposes of this Annex, the following definitions shall apply:

‘biogenic emissions capture with carbon storage activity’ or ‘BioCCS activity’ means an activity resulting in a process of capturing biogenic CO2, followed by transport and permanent storage of that biogenic CO2 by injection at a geological storage site for which a valid permit exists in accordance with Article 8 of Directive 2009/31/EC;
‘biogenic CO2’ means CO2 produced from a source of biomass, biofuel, bioliquid or biomass fuel by a chemical or biological process acting on the carbon atoms therein, including combustion, oxidation, anaerobic digestion and fermentation;
‘associated GHG emissions’ means the increase in direct and indirect greenhouse gas emissions over the entire lifecycle of the activity which are attributable to its implementation;
‘capital emissions’ means the emissions associated with the construction of facilities and equipment associated with an activity;
‘captured CO2’ means CO2 captured and concentrated from a point source of CO2 or from the atmosphere;
‘capture facility’ means a facility that captures CO2 from the atmosphere or from a biogenic-CO2 containing stream and conditions it to a form that is ready to be transported or stored, including in terms of CO2 purity and pressure;
‘certification period’ means the period between a re-certification audit of an activity and the most recent preceding certification audit or re-certification audit of that activity;
‘CO2 fugitives’ means any irregular or unintended CO2 emissions from sources that are not localised, or are too diverse or not substantial enough to be monitored individually;
‘CO2 venting’ means an intentional release of CO2 occurring for operational or safety reasons;
‘exit point’ means a point at which CO2 is transferred out of the capture facility for the purpose of either transport or storage, which excludes any smokestack, flue or other outlet at the capture facility from which CO2 is released into the atmosphere;
‘fossil CO2’ means CO2 generated from fossil carbon, which is inorganic and organic carbon that is not zero-rated carbon under Implementing Regulation (EU) 2018/2066;
‘permanent geological storage’ means storage of CO2 at a geological storage site permitted under Directive 2009/31/EC;
‘point source of CO2’ means a natural or anthropogenic source of gases that has a CO2 concentration higher than that in the free atmosphere due to the generation of CO2 by an oxidation process or other chemical process or the release of CO2 from some form of storage or containment;
‘useful heat’ means heat generated to satisfy an economically justifiable demand for heat, for heating or cooling purposes.

Contributors

Sebastian Green, Ph.D.

Xueya Lu, Ph.D.

Chris Pollard

Jasmin Kazazi

Isometric

Contents

Summary

Description of the Carbon Removal Activity

Eligibility

Carbon Removal Activities With CO2 Capture and Geological Storage

Activity Period, Monitoring Period and Certification Period

Bio-CCS Activities

Activity Period

Monitoring Period

Certification Period

Planning and Reporting

Activity Plan

Monitoring Plan

Monitoring Report

Quantification of Baseline, Total Carbon Removal and Associated GHG Emissions

Bio-CCS Activities

GHG Sources and Sinks

Baseline

Quantification of the Total Removals of the Activity

Identification of Captured CO2 Streams

Fraction of Captured CO2 to Be Counted Towards the Total Carbon Removal

Segregated CO2 Stream

Non-Segregated CO2 Stream

Quantification of the Greenhouse Gas Emissions Associated With the Activity

Capture of CO2 From Biogenic Emissions

Quantification of Total CO2 Captured

Capture of CO2 From Partially Biogenic Streams

Quantification of Associated GHG Emissions

Emissions From the Capture Facility

Emissions From Inputs I

Monitoring and Reporting I

Transport of CO2

Quantification of Fugitive, Vented and Leaked Emissions of Captured CO2

CO2 Losses: Method A

CO2 Losses: Method B

Fugitive Emissions

Vented Emissions

Leakage Events

Quantification of Associated GHG Emissions for Transport

Emissions From Non-Pipeline Transportation of CO2

Emissions From Transportation Infrastructure

Monitoring and Reporting II

Injection of CO2 at Storage Sites

Quantification of CO2 Entering the Storage Site

Application of Mass Balance Rules

Quantification of Fugitive and Vented Emissions of Captured CO2

Quantification of Associated GHG Emissions

Emissions From the Storage Site

Emissions From Inputs II

Monitoring and Reporting III

Common Elements for Quantification

Completeness and Materiality

Net Consumption of Useful Heat or Electricity

Additional Biomass Consumption

Bioenergy Facilities Generating Only Electricity

Bioenergy Facilities Generating Only Heat

Bioenergy Facilities Generating a Mix of Heat and Electricity

Emission Factors

Electricity

Heat

Biomass

Inputs and Fuels

Transport

Capital Emissions

Measured Data and Uncertainties

Confirmation of Origin of CO2 Stream

Carbon Storage and Liability

Bio-CCS Activities

Sustainability

Minimum Sustainability Requirements

Climate Change Mitigation

Climate Change Adaptation

Sustainable Use and Protection of Water and Marine Resources

Transition to a Circular Economy, Including the Efficient Use of Sustainably Sourced Bio-Based Materials

Pollution Prevention and Control

Protection and Restoration of Biodiversity and Ecosystems Including Soil Health, as well as Avoidance of Land Degradation

Biomass Sustainability

Avoidance of Unsustainable Demand for Biomass Raw Material

Requirements for Bio-CCS

Voluntary Compensation of Biomass Used by Carbon Removal Activities

Carbon Removal Activities With CO₂ Capture and Geological Storage

Identification of Captured CO₂ Streams

Fraction of Captured CO₂ to Be Counted Towards the Total Carbon Removal

Segregated CO₂ Stream

Non-Segregated CO₂ Stream

Capture of CO₂ From Biogenic Emissions

Quantification of Total CO₂ Captured

Capture of CO₂ From Partially Biogenic Streams

Transport of CO₂

Quantification of Fugitive, Vented and Leaked Emissions of Captured CO₂

CO₂ Losses: Method A

CO₂ Losses: Method B

Emissions From Non-Pipeline Transportation of CO₂

Injection of CO₂ at Storage Sites

Quantification of CO₂ Entering the Storage Site

Quantification of Fugitive and Vented Emissions of Captured CO₂

Confirmation of Origin of CO₂ Stream