Energy Use Accounting

1.0 Introduction

This Modulemodule (Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.) describes how to calculate emissions (The term used to describe greenhouse gasenergy-related emissions tomust thebe atmospherecalculated asin a resultcarbon of Project activities.) related to energy use forremoval Carbon Dioxide Removal (CDR) (Activities that remove carbon dioxide (CO₂) from the atmosphere and store it in products or geological, terrestrial, and oceanic Reservoirs. CDR includes the enhancement of biological or geochemical sinks and direct air capture (DAC) and storage, but excludes natural CO₂ uptake not directly caused by human intervention.)projectsproject (An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.) asso partthat they can be subtracted in the net CO₂e (The amount of CO₂ emissions that would cause the same integrated radiative forcing or temperature change, over a given time horizon, as an emitted amount of GHG or a mixture of GHGs. One common metric of CO₂e is the 100-year Global Warming Potential.)removal (The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.) calculation. Furthermore, this module applies to all carbon removal pathways (A collection of Removal or Reduction processes that have mechanisms in common.), ensuring a consistently rigorous standard in how energy-related emissions are quantified and reported between different carbon removal projects and approaches.

2.0 System Boundaries

[math: CO_2e_{Energy\ R}] must account for all operations and support systems that consume energy within the removal process, for example through electricity or fuel, as specified in Section 3 of this module. These operations and support systems are denoted as [math: k].

Primarily non-road/rail/air/maritime mobile sources are included within this boundary, such as fork trucks and loaders used for material handling. However road, rail, air and martime mobile emission sources are excluded from [math: k], such as electric or diesel vehicles, as they are accounted for in [math: CO_2e_{Transportation,\ R}].

Where possible, project greenhouse gasproponents (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) should account for emission impacts of electricity usage based on the same grid regions (A geographically precise and internally well-connected energy distribution and use area representing a subsection or the entirety of a synchronized electricity grid. The assignment of a project to a grid region should be based on the location of the project’s point of interconnection within the topology of the electricity system, rather than the physical location of the project itself.) (well-connected energy distribution and use areas) as endorsed by national governments. For facilities within projects that consume large quantities of electricity, known as intensive facilities, accounting for the consequential (The analysis of specific Uncertainties, hazards and scenarios inherent in complex systems such as the natural and engineered environment, aiming to describe how systems-level environmentally relevant flows will change in response to possible decisions.) emission impacts of electricity usage may also be required. More details on when this is applicable can be found in Section 3.2.1.

3.0 Calculation of CO₂e_{Energy, R}

Emissions associated with energy usage include the following potential emissions sources,

[math: CO_2e_{Energy,\ R} = CO_2e_{Electricity,\ R} + CO_2e_{Fuel,\ R}]

(Equation 1)

Where:

• [math: CO_2e_{Energy,\ R}] = the total quantity of GHG) (Those gaseous constituents of the atmosphere, both natural and anthropogenic (human-caused), that absorb and emit radiation at specific wavelengths within the spectrum of terrestrial radiation emitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).) accounting. This Module applies to all CDR pathwaysemissions (Amass collectionunits of Removal or Reduction processes that have mechanisms in common.)CO₂e, ensuringincluding, at a consistently rigorous standard in how energy-related emissions are quantified and reported between different projects and approaches.

2.0 Future Versions

This Module was developed based on the current state of the artminimum, publicly available science regarding energy emissions accounting. This Module will be updated in future versions as the underlying science evolves and the availability of high-quality data and documentation in the energy market increasesCO₂, for example regarding emission factors (An estimate of the emissions intensity per unit of an activity.), temporal matching and power purchase agreements.

This Module will be reviewed at least annually when substantial changes of data availability in the energy market occur, or when there are substantial advances in understanding of scientific concepts relevant to emissions accounting for energy usage.

Isometric recognizes that best practices for supplying energy to CDR projects are still evolving. Isometric will continue to engage with stakeholders (Any person or entity who can potentially affect or be affected by Isometric or an individual Project activity.) and the scientific community to assess the rigor and operability of accounting approaches, including temporal matching and emissions matching. Any future changes to the approach outlined in this Module will be conducted in consultation with a range of stakeholders and the scientific community to ensure a robust transition to the best available approaches, while maintaining operational integrity for existing projects which are continuing to be established under an evolving governance landscape.

Isometric is committed to progressively increasing the rigor of energy emissions accounting requirementsCH₄, and will introduce more robust approaches as soon as they are supported by the evolving science and demonstrably operable under prevailing market conditions.

3.0 System Boundaries

TheN₂O emissions) associated with energy use must accountconsumption for alla operationsremoval, that[math: consumeR], in tonnes;

[math: withCO_2e_{Electricity,\ EnergyR}] Use are denotedand [math: CO_2e_{EnergyFuel,\ R}] must account for operations and support systems that consume electricity or fuel within a removal, denoted as [math: k]. This may be calculated on an individual or combined basis (e.g., for an individual piece of equipment, a sub-process, and/or a Project) as long as all operations and support systems, [math: k], are accounted for.

3.1 Calculation Approach

Equation (1) and the calculation approaches in Section 3 can also be followed for a batch, [math: n], or for a reporting period, [math: RP].

3.2 Calculation of CO₂e_{Electricity, R}

Electricity-related emissions typically are indirect emissions associated with generation and transmission of electricity by another entity (electric utility) which is used by the process.

3.2.1 Definition of intensive and non-intensive facilities

The calculation approach in this module distinguishes between the types of electricity consuming facilities used for a removal, [math: R], within a project. [math: CO_2e_{Electricity,\ R}] is calculated from the sum of electricity usage across facilities for a given removal, [math: R].

SourcesThe (Anytwo processcategories orof activityprojects thatrelevant releasesto athis greenhousecalculation gasapproach are intensive projects, anwhich aerosolhave the potential for significant amounts of electricity utilization, orand anon-intensive precursorprojects. A facility is considered to be non-intensive for the purposes of a greenhouseproject gasif intoit uses less than 10 GWh and where the atmosphereestimated electricity use per ton of CO₂ sequestration is less than 50 kWh.) includedFacilities inthat thisuse Module’sgreater scopethan 10 GWh of electricity or where estimated electricity use per ton of CO₂ sequestration is greater than 50 kWh are: classified as intensive facilities.

• Non-mobile

  Any machinery;

• Primaryintensive non-road/rail/air/maritimefacilities mobilewithin sourcesa project, such as forkdirect trucksair capture facilities, must evaluate and loadersaccount for the consequential impact of electricity usage on the system they are procuring electricity from according to the approach in Section 3.2.3. Any non-intensive facilities within a project do not need to account for the consequential impact of electricity usage, and must follow the calculation approach in Section 3.2.2.

3.2.2 Calculation of CO₂e_{Electricity, R} for non-intensive facilities

The following calculation approach must be followed for non-intensive facilities:

[math: CO_2e_{Electricity,\ R} =\sum_{1}^{N}kwh_{k}\cdot EF_{Elect,\ r}]

(Equation 2)

Where:

• [math: CO_2e_{Electricity,\ R}] = total GHG emissions resulting from electricity use for a removal [math: R], in tonnes;
• [math: kwh_{k}] = total kilowatt hours of electricity used for materialeach handlingoperation or support system, [math: k], occurring in a non-intensive facility as part of a removal, [math: R]; and
• [math: EF_{Elect,\ r}] = Emission factor in tonnes [math: CO_2e]/[math: kwh] for a given electrical grid located in region, [math: r].

If a project relying on a non-intensive facility wishes to reduce their energy emissions through the purchase of qualifying electricity then they may use Equations 3 and small4 personalreplacing transport[math: modesEF_G] with [math: EF_{Elect,\ r}]. Project proponents will be responsible for collecting sufficient documentation to submit these calculations.

3.2.3 Calculation of CO₂e_{Electricity, R} for intensive Projects

For intensive facilities a consequential accounting approach is adopted (see Appendix 1 for further information), which is designed to be conservative (Purposefully erring on the side of caution under conditions of Uncertainty by choosing input parameter values that will result in a lower net CO₂ Removal or GHG Reduction than if using the median input values. This is done to increase the likelihood that a given Removal or Reduction calculation is an underestimation rather than an overestimation.) such that it avoids overestimating the net carbon removal of a project. Emission impacts resulting from both the consumption of grid electricity and the direct procurement of power from individual generators are considered as part of this approach.

3.2.3.1 Exemption for facilities subject to approved cap-and-trade programs

Facilities that source electricity from within jurisdictions that have implemented sufficiently rigorous GHG cap-and-trade programs shall assume a consequential emissions rate of zero for all electricity consumption within these jurisdictions. See Appendix 2 for further information on this exemption. Currently the European Union (EU) Emissions Trading Scheme is the only cap-and-trade jurisdiction approved as sufficiently rigorous under this Module.

3.2.3.2 Other facilities

For facilities not subject to the above exemption total emissions for a removal, [math: R], are calculated as the sum of the hourly emissions, [math: CO_2e_{Electricity,\ L}], over all hours of electricity consumption within that removal:

[math: CO_2e_{Electricity,\ R} = \sum CO_2e_{Electricity,\ L}]

(Equation 3)

Where:

• [math: CO_2e_{Electricity,\ R}] = total GHG emissions resulting from electricity use for a removal, [math: R], in tonnes; and
• [math: CO_2e_{Electricity,\ L}] = the total GHG emissions associated with [math: kwh_{L}] kilowatt-hours of electricity consumption in the hour in question for a project relying on an intensive facility, occurring within a removal, [math: R], in tonnes.

[math: CO_2e_{Electricity,\ L}] is calculated as follows:

[math: CO_2e_{Electricity,\ L} = max \bigg(0,kwh_{L} - \sum_{p}G_{p}\cdot m_{p}\bigg) \cdot EF_G + \sum_{p} \frac {G_{p}\cdot EF_{p}}{m_{p}}]

(Equation 4)

Where:

• [math: kwh_{L}] = total kilowatt-hours of electricity consumption in the hour in question;
• [math: G_{p}] = the amount of qualifying electricity procured for physical delivery from generator, [math: p], to the project in the same hour;
• [math: m_p] = derating factor used to moveaccount stafffor aroundtransmission projectlosses sites;from and
• Fuelsdelivery combusted to provide heat, steam, startup energy, or toof power eligiblefrom mobilegenerator, sources[math: p];
• [math: EF_G] = the hourly short-run marginal emissions rate (The estimated change in total greenhouse gas emissions from a structurally-fixed electricity system that would result from an incremental change in electricity demand at a specific point in the system at a specific time.

Refer Short-run marginal emissions rates reflect the emissions associated with real-time changes in output from specific marginal generators in response to the GHGhypothetical Accountingchange Modulein v1demand.1 They do not reflect the potential for a persistent change in demand to incentivize entry of new generating facilities into the calculationelectricity guidelinessystem (i.e., structural change). Multiple methodologies for transportationcalculating (includingshort-run roadmarginal emissions rates from available grid data exist, railbut all aim to quantify the same impact. Short-run marginal emissions rates are provided directly at hourly or sub-hourly resolution by some grid operators, air and maritimein mobileother emissioncases sourcesthey are calculated and made available by third-party vendors. Some grid operators also provide temporally granular data on ‘fuels on the margin,’ from which project proponents may calculate marginal emissions rates using average fuel-specific emissions factors from the grid region in question.) (emissions associated with real-time changes in output from specific marginal generators in response to the hypothetical change in demand) of the local electricity grid at the project’s point of interconnection, and;

3.2.4 Eligibility Criteria for Qualified Electricity

Electricity consumption may be subdivided into consumption of 'Qualified' electricity and 'non-Qualified' electricity:

• ‘Qualified’ electricity usage requires accounting for only the emissions associated with individual identified generators, including embodied emissions (Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.)
• ‘non-Qualified’ electricity requires accounting (includingfor consequential impacts of the production of products/ feedstocks (Raw material which is used for CO₂ Removal or GHG Reduction.)).
  [Module: ghg-accounting v1.1]

  Refer to the GHG Accounting Module for calculation guidelines.

4.0 Calculation of CO2eEnergy,RP

Emissions associated with energy usage include theelectricity use of both electricity and fuel. The following calculation approach must be followed for the calculation of [math: CO_2e_{Energy,RP}]:

[math: CO_2e_{Energy,RP} = CO_2e_{Electricity,RP} + CO_2e_{Fuel,RP}]

(Equation 1)

Where:

• [math: CO_2e_{Energy,RP}]: the total GHGon emissions associated with energy consumption for a Reporting Period, [math: RP], in tonnes of CO2e (The amount of CO₂ emissions that would cause the same integrated radiative forcing or temperature change, over a given time horizon, as an emitted amount of GHG or a mixture of GHGs. One common metric of CO₂e is the 100-year Global Warming Potential.).
• [math: CO_2e_{Electricity,RP}]: the total GHG emissions associated with electricity usage for a Reporting Period, [math: RP], in tonnes of CO2e.
• [math: CO_2e_{Fuel,RP}]: the total GHG emissions associated with fuel usage for a Reporting Period, [math: RP], in tonnes of CO2e.

[math: CO_2e_{Electricity,RP}] and [math: CO_2e_{Fuel,RP}] must account for all operations and support systems that consume electricity or fuel within the CDR process. This may be calculated on an individual or combined basis, provided that all operations within the process are accounted for.

5.0 Calculation of CO2eElectricity, RP

This Module provides accounting requirements for the following types of electricity:

• Behind-the-meter provision: Projects may establish generation “behind-the-meter”. Project Proponents (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) must follow the quantification requirements in Section 5.1.
• Grid-based electricity: electricity which is obtained from the electricityentire grid tovia whichhourly Themarginal Projectemissions isanalysis

To connected.be Projects must follow the quantification requirements in Section 5.2.

5.1 Calculation of CO2eElectricity, RP With Behind-The-Meter Electricity Provision

Project Proponents may elect to establish power generation "behind-the-meter". Behind-the-meter electricity provision refers to generation that supplies electricity directly to The Project without passing through the local transmission grid. This may occur either via a direct physical connection or because the CDR process is integrated into the electricity generation process itself. Behind-the-meter generators may be owned and operated by The Project Proponent or by a third party. Additionally, they may be existing assets, or assets built at the same time as the CDR project.

Life cycle emissions associated with electricity produced by behind-the-meter generators and used by The Project must be quantified. If the electricity produced by the generator is used solely by The Project, the generator must be fully considered as part of The Project's system boundary (GHG sources, sinks and reservoirs (SSRs) associated with the project boundary and included in the GHG Statement.). If the electricity supply produced by the generator is delivered to the grid or other facilities as well as The Project, emissions associated with electricity provision to The Project must be quantified in line with the requirements for [math: f_p] in Section 5.5 and proportionally allocated to The Project.

Projects utilizing electricity from generators that meet bothall of the following eligibility criteria must also account for Energy leakage (The increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities.) if the following are true:

• Generator was in operation for more than 36 months before The Project was initiated; and
• The generator supplies electricity to the local electricity grid.

Energy leakage represents the indirect greenhouse gas emissions arising when a Project consumes electricity that would otherwise have been supplied to the grid, or when a Project creates a parasitic load that reduces the net electricity supplied to the grid. Energy leakage is quantified by determining the total reduction in electricity supplied to the grid resulting from the CDR process and multiplying this by the average grid intensity factor ([math: f_{grid}]).

Project electricity demand may be supplied entirely by behind-the-meter generation or partially supplied. The accounting requirements for each are set out below:

• Full Supply: No additional electricity emissions accounting is required beyond the life cycle emissions of the generator and Energy Leakage (if applicable) described above.
• Partial Supply: When demand is partially supplied, the remaining electricity requirement must be quantified in accordance with Section 5.3 and Section 5.4. For the purpose of these calculations, the facility’s net grid import is equal to the total electricity demand minus the behind-the-meter generation supplied to The Project.

For the determination of a facility as intensive or non-intensive, the facility's relevant electricity consumption is equal to the total electricity demand minus the behind-the-meter generation supplied to The Project. Consequently, electricity supplied by behind-the-meter generation is excluded from the consumption total used to determine if the 200 GWh threshold is met.

5.2 Calculation of CO2eElectricity, RP With Grid-Based Electricity Provision

Equation 2 must be followed for emissions associated with provision of electricity from the grid.

[math: CO_2e_{Electricity,\ RP} = f_{grid} \sum_{i=1}^{N}E_i]

(Equation 2)

Where:

• [math: CO_2e_{Electricity,RP}]: the total GHG emissions associated with electricity usage for a Reporting Period, [math: RP], in tonnes of CO2e.
• [math: f_{grid}]: grid average emissions factor, in tonnes of CO2e/kWh. Details of requirements for acceptable emissions factors can be found in Section 5.5.
• [math: E_i]: electricity usage in hour [math: i], in kWh.
• [math: N]: total number of calendar hours for Reporting Period, [math: RP].

Projects may reduce electricity emissions through procurement of low-carbon power (See Section 5.4).

5.3 Calculation of CO2eElectricity, RP With Electricity Environmental Attribute Certificate Procurement

A Project may wish to reduce its energy emissions through the procurement of Electricity EACs, where electricity is procured by contract purchase from renewable sources for the exclusive use of The Project. Note that Electricity EACs are known by different names depending on the jurisdiction, including Renewable Energy Certificates (RECs) and Guarantees of Origin (GOOs). In this Module, the term Electricity EAC is used as an umbrella term covering all such instruments.

To use Electricity EACs, Project Proponents are required to account for emissions associated with the electricity generation following the requirements for [math: f_p] set out in Section 5.5. Furthermore,

[math: CO_2e_{Electricity, RP} = f_{grid} \left[ \left( \sum_{i=1}^{N}E_i \right) - \left( \sum_p G_p \right) \right] + \sum_p f_p G_p]

3.

[math: f_p]: emissions factor for generation by generator type [math: p], in tonnes of CO2e/kWh.

[math: G_p]: total amount of energy procured for removal R by generator type p, in kWh.

[math: \left( \sum_{i=1}^{N} f_{grid,i} \cdot E_i \right) - \left( \sum_p \sum_{i=1}^{N} (f_{grid,i} - f_{p,i}) \, G_{p,i} \right) \leq 0]

(Equation 6)

Where:

• [math: f_{p,i}]: emissions factor for generation by generator type [math: p] in hour [math: i], in tonnes of CO2e/kWh.
• [math: G_{p,i}]: amount of energy procured for removal R by generator type p in hour [math: i], in kWh.

Alternative approaches may be implemented (for example using marginal and hourly emission factors) to demonstrate that The Project's low-carbon power procurement sufficiently mitigates the emissions impact of its electricity consumption.

Whether an intensive Project implements the Emission Screen, or not, must be transparently reported in the PDD.

5.5 Acceptable EmissionsEmission Factors and Rates - CO₂e_{Electricity, RPR}

3.2.5.1 EF_Elect,r and EF_p

[math:Emission f_{grid}]factors -(An estimate of the emissions factorsintensity per unit of an activity.) used must:

• Be technology-specific to the mix of electricity generation methods in the connected electric grid;
• Wherever available, represent hourly average emission factors when used in Equations 2 and 3, and in the project electricity consumption term (left-hand side) of Equations 5 and 6. Hourly average emission factors must only be used in Equation 4 if low-carbon power features hourly time stamps, otherwise annual average emission factors must be used. In the procurement term (right-hand side) of Equations 5 and 6, hourly average emission factors must only be used in Equation 6, where hourly generation data for procured power is available or can be derived. Where hourly generation data is not available (Equation 5), annual average grid emission factors must be used in the procurement term.
• Wherever available, be reported on a residual-mix basis, meaning that any generators within a grid region which are subject to contract purchase (e.g., through RECs/PPAs) are excluded from the average emissions calculation. Project Proponents must declare whether such data is available in the region of operation, and utilize such data wherever possible. Where residual mix factors are not available, national grid average factors are considered acceptable.
• Be reported on a consumption basis, meaning that all net physical energy imports/exports across the grid boundary should be reflected;
• Account for the full life cycle emissions associated with electricity generation, including direct emissions from power generation, transmission and distribution losses, and upstream life cycle emissions associated with extraction, refining and transportation of primary fuels (i.e., from cradle-to-gate);
• Be for the specific region (nation, state, locality) where the electricity consumption is occurring, with the most granular or site-specific data source preferred;
• Be for the most recent published year. Wherever possible, the utilized emissions factors must correspond to those most recently published by the relevant authority in the region of project operations; and
• Account for total GHG emissions as CO2e. Separate emissions factors for each GHG may be utilized, and the calculated emissions should be converted to CO2e using the 100-yr Global Warming Potential (A measure of how much energy the emissions of 1 tonne of a GHG will absorb over a given period of time, relative to the emissions of 1 ton of CO₂.) (GWP) for the relevant GHG, based on the most recent volume of the IPCC Assessment Report (presently the Sixth Assessment Report).

[math: f_p] - emissions factors used must:

• Be technology-specific to the method of electricity generation;
• Account for all embodied emissions associated with the establishment of procured generators by amortizing on a per unit electricity generation basis. If embodied emissions are not included within the used emissions factor, then they must be calculated separately and allocated to The Project on a proportional basis relative to the usage of the generating asset over its anticipated lifetime and generation capacity;
• Accountaccount for the full life cycle emissions associated with electricity generation and include direct emissions from power generation (i.e., fuel combustion), upstream emissions associated with fuel production, equipment manufacture, and equipment decommissioning and disposal at a minimum;
• Accountbe for anythe necessaryspecific deratingregion factors(nation, associatedstate, locality) where the electricity production occurring, with energythe lossmost duringgranular transmissionor betweensite-specific data source preferred;
• be for the generatingmost facilityrecent andpublished The Project. Where derating factors are not applied in the utilized emissions factors, The Project Proponent must additionally account for these. For example, derating factors for transmission losses may be estimated using the approach of Sadovskaia et al. (2019)4, or any other suitably justified methodyear; and
• Accountaccount for total GHG emissions as CO₂e. Separate emissionsemission factors for each GHG may be utilized, and the calculated emissions should be converted to CO₂e using the 100-yr Global Warming Potential (GWP) for the relevant GHG, based on the most recent volumeIPCCUN 100-year global warming potentials (A measure of thehow IPCCmuch Assessment Report (presentlyenergy the Sixthemissions Assessmentof Report1 tonne of a GHG will absorb over a given period of time, relative to the emissions of 1 ton of CO₂.).

Regional or subnational location-based grid average emissions factors must be used where available for the calculation of [math: f_{grid}]. These must represent net physical energy imports and exports across the grid boundary and all electricity production occurring in a defined grid distribution region that approximates a geographically precise energy distribution and use area.

Applicable life cycleAcceptable emission factors include those utilized in the Argonne National Laboratory GREET Model^{^21}, California Air Resources Board modified GREET model (CA-GREET)^{^32}, Ecoinvent database^{^43}, US Federal Life Cycle Inventory database or LCA Commons^{^54}, and similar databases used in common life cycle assessment (LCA (An analysis of the balance of positive and negative emissions associated with a certain process, which includes all of the flows of CO₂ and other GHGs, along with other environmental or social impacts of concern.)) practices or tools (such as OpenLCA, SimaPro, or GaBi (LCA for Experts) ).

EmissionOther emission factors may also be used that do not incorporate the full life cycle emissions associated with power generation if these additional life cycle emissions are accounted for separately. For example, real-time carbon intensity factors⁵ may also be utilized, provided they are time-aligned with operations and account for CO₂, CH₄, and N₂O. Power generation emission factors based on fuel combustion from sources such as EIA or US EPA (A United States Government agency that protects human health and the environment.) (i.e., AP-42) may also be utilized if the additional upstream and downstream life cycle considerations are addressed. A combination of such emission factor sources may also be used, such as real-time or daily CO₂ data plus EPA or EIA CH₄ and N₂O factors.

3.2.5.2 Short-run Marginal Emission Rates - EF_G

Project proponents may estimate the short-run marginal emissions (SRME) rate, [math: EF_G], associated with consumption of grid electricity at a project’s point of interconnection, using hourly SRME data provided by a grid operator, government, or third-party provider, wherever such data is available.

Emission rates must:

• incorporate the most geographically-precise SRME data offered by the chosen provider:
  • either the individual node most representative of the project’s point of interconnection to the grid in the case of nodal-resolution marginal emissions data,
  • or the smallest data region containing the project’s point of interconnection in the case of regional-resolution marginal emissions data.
• include upstream emissions
  • if the marginal emissions data sets used to calculate [math: EF_G] do not incorporate upstream emissions, the project proponent should apply a 1.2x mulitplier to the baseline (A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.) emissions factor in order to correct for upstream impacts.

If a project is located in a grid region for which no hourly-resolution SRME data is available from any provider, or if the project proponent opts not to use such data, the project proponent should assign a proxy (A measurement which correlates with but is not a direct measurement of the variable of interest.) marginal emission rate to all net electricity consumption from the grid.

• To calculate this proxy rate, the project proponent should:
  • first identify all grid regions that share a direct transmission connection with the project’s local grid region;
  • subsequently calculate average emission factors for all fuel types that accounted for more than 5% of total generation in this combined region in the year prior to the reporting period. This may be done by dividing the annual total reported GHG emissions from all plants of a given fuel type by their annual total electricity generation.
  • an exception to this rule exists for facilities operating in grid regions that publish LMPs for all hours in which the average LMP at the project’s point of interconnection is less than the equivalent of USD 10/MWh in 2022. In such cases, the project should be assumed to have consumed electricity from carbon-free resources that would otherwise have been curtailed, and the value of [math: EF_G] should be reported as zero rather than the typical proxy value. If the grid region in which the Project is located does not publish LMPs, but at least one adjacent region does, the Project may use the average of all published LMPs at the intertie points between the Project’s grid region and the adjacent grid regions as a proxy for the LMP in the Project’s grid region.

Emission rates must not:

• use non-consequential metrics such as average grid emissions intensities in reporting the additional emissions impact of grid electricity consumption. Average emissions rates can be used to divide responsibility for emissions among all electricity consumers, but they do not reflect the impacts of an individual consumer’s actions on total emissions; or
• be estimated using [math: EF_G] SRME data from grid regions other than the one in which the project is located.

3.2.5.3 Derating Factors - m_p

For every generating facility, [math: p], the value of [math: G_{p}] (see Section 3.2.3) in a given hour must be equivalent to the average metered A/C power output of the Project in that hour. If the facility is co-located ‘behind-the-meter’ with the Project, the value of [math: m_{p}] should be equal to 1. If the generating facility is not co-located with the Project, the value of [math: m_{p}] should be revised to 0.95, in order to account for transmission losses⁶.

3.2.6 Measurements - CO₂e_{Electricity, RPR}

ThePrimary primary measurementmeasurements considered in calculation of electricity emissions isare:

• for non-intensive facilities:
  • [math: E_ikwh_k]: (Equation 2) - total amountkilowatt hours of electricity used byfor Theeach Projectoperation inor hoursupport system, [math: ik].; and
• for intensive facilities:
  • [math: kwh_L] (Equation 4) - total kilowatt hours of electricity used for the hour in question

Measurements must be made using a utility grade power meter, or an independent power meter installed by The Project Proponent,metering with hourly reporting frequencyat ata minimum. PreferenceMeters ismust for meters withhave an accuracy of better than 2% of reading for total electricityenergy consumption, as reported in units of kWhkwh. However,

Any meters with accuracy of worse than 2% of reading for total electricity consumption are acceptable provided that the accuracy of the meter is reported and an appropriate discount is applied to The Project net-CDR calculation. Metersused must be calibrated initially and at regular intervals in accordance with manufacturer specifications to ensure accuracy.

5

3.2.7 Required Records and& Documentation - CO₂e_{Electricity, RPR}

Electricity usage must be monitored for all operations within the gate at each location of their utilization relevant to project operation. The Projectproject Proponentproponent must maintain records of any electricity use for any operation or support system, [math: k], within the gate of a removal, [math: R]'s, process, that consumes electricity. This is in addition to documentation listed in Section 53.2.4.2), if applicable to Thea Projectproject.

• Allowable electricity records include, but are not limited to:
  • Onon-site electricity meter readings (i.e., utility electric meter), whether owned by the site owner orof by the electric utility, either electronic or manually logged; or
  • Independentindependent power meter readings for metering equipment installed by Thethe Projectproject Proponentproponent to measure power consumption of the process.;

If other equipment or processes not related to the removal, [math: R]’s, process are included in meter readings or utility bills, electricity usage may be allocated to such processes based on sub-metering data, equipment maximum electricity consumption ratings and operating hours for each sub-system and percentage of total maximum electricity consumption accounted for by the meter or utility bill, or by other justifiable allocation methods which must be reviewed and accepted during third party verification.

All records of electricity usage, including meter specificationspecifications and calibration records, must be maintained by Thethe Projectproject Proponentproponent for a period of at least five years.

6

3.03 Calculation of CO₂e_{Fuel, RPR}

Process emissions may result from combustion of fuels to provide thermal energy to support equipment startup and operations,operation or to supply steam or other thermal energy sources for operations, or to power primary non-road/rail/air/maritime mobile sources. Fuels for the provision of heat to The Project can be supplied from outside sources, or may be produced as a result of activities within The Project gate.

The calculation approach in Equation 7 must be followed for calculation of [math: CO_2e_{Fuel, RP}].

[math: CO_2e_{Fuel,\ RPR} = \sum_{k=1}^K{k} m_{fuelFuel,\ k}f_\cdot\ EF_{fuel,kFuel}]

(Equation 75)

Where:

• [math: CO_2e_{Fuel,\ RPR}]: = total GHG emissions resulting from thermal energy generation via fuel combustion for a Reporting Period,removal [math: RPR], in tonnes of CO2e.[math: CO_2e]
• [math: m_{fuelFuel,\ k}]: = total mass, volume, or heating value of fuel used for each operation or support system, [math: k], usedas forpart of a Reporting Periodremoval, [math: RPR] in appropriate units e.g. (kg, gal, ft³, therms, etc. as required based on emission factor units)
• [math: f_EF_{fuel,kFuel}]:= emissionsEmission factor forin fueltonnes [math: kCO_2e] in tonnes of CO2e/unit.
• [math: K]: total number of distinct fuels, [math: k], used for a Reportinggiven Period,fuel [math:type RP].where unit is specific to each fuel type and factor

Project ProponentsOperations may consider the use of waste heat to reduce emissions associated with heat provision for a project. Waste heat utilization must meet the criteria described in Section 6.1 to be eligible for discounting against project heat usage.

Project Proponents may consider procurement of Fuel EACs to reduce emissions associated with the use of liquid fuels. Fuel EACs must meet Eligibility Criteria set out in Section 6.2.1 and must follow the calculation procedures outlined in Section 6.2.2.

6.1 Waste Heat Eligibility Criteria

Project Proponents may consider the use of waste heat topotentially reduce the emissions associated with fuelenergy usage of a projectprocess. WasteA true waste heat sourcessource dodoes not require accounting of GHG emissions associated with the production and delivery of the utilizedwaste thermalheat energyto the project gate. Waste heat utilization must meet the criteria described in TableSection 3.3.1 to be eligibleconsidered for discounting against projectwaste heat usage.

Any activities specifically developed inside Thethe Projectproject gate to handle and utilize the waste heat, however, must be accounted for in the life cycle analysis. These potentially include, but are not limited to:

• Wastewaste heat distribution systems, including pumps, piping, or other equipment;
• Wastewaste heat upgrading processes, such as heat pumps, booster pumps, otheror other equipment; and
• Wastewaste heat conversion processes, such as waste heat- to- power technologies, (e.g.such as organic Rankineranking cycle generators).

Equipment and energy usage associated with waste heat utilization must be accounted for in accordance with the requirements of this Modulemodule and the SectionEmbodied 4.1Emissions of the GHG Accounting Module v1.1module.

3.3.1 Waste Heat Eligibility Criteria

Waste heat utilization must meet all of the following criteria in Table 3 to be considered true waste heat, and be exempt from GHG emissions accounting. For projects using heat that do not meet these criteria, emissions associated with the heat production shall be considered in the LCA, including leakage emissions as appropriate.

Table 3: Eligibility Criteria for Waste heat

6.2 Calculation of CO2eFuel, RP With Fuel Environmental Attribute Certificate Procurement

6.2.1 Fuel Environmental Attribute Certificate Eligibility Criteria

Under this Module, Projects are permitted to use Fuel EACs for low-carbon liquid fuels to substitute for some, or all, of project fuel usage is permitted. Fuel EACs are an instrument which Project Proponents can purchase to financethrough the use of low-carbonmore fuelsefficient by a third party in situations where the third party would otherwise have used conventional fuel. The net effect of the Fuel EAC purchase attempts to yield the same outcome as if The Project Proponent had used low-carbon fuel within their own supply chain. Fuel EACs can offer additional flexibility to Projects where constraints may limit availability of low-carbon fuels in the region of project operations. In the context of this Module “low-carbon fuels” refers to alternative liquid fuels with a lower carbon intensity than a conventional equivalent, for example biodiesel as a substitute for conventional diesel.

Fuel EACs may only be used to discount Related project emissions. Related emissions are indirect emissions from SSRs (Sources, Sinks and Reservoirs) not controlled by The Project Proponent (typically occurring upstream or downstream of the project site). Fuel EACs transfer the environmental attribute of low-carbon fuel, but do not change the physical fuel combusted as a Controlled emission (i.e., direct emissions equivalent to Scope 1). This restriction preserves quantification integrity and avoids double claiming for organisational claimsequipment (e.g. under ICAO CORSIA5).

Isometric evaluates Fuel EAC programs, registries and methodologies against high-levelefficiency integrity and issuance and claiming principles that are aligned with ICAO’s CORSIA5 framework. Methodologies and registries that are considered acceptable under this Module are those that meet CORSIA-aligned requirements. Best practices for Fuel EACs are still evolving and therefore Isometric will continue to engage with stakeholders and the scientific community to assess the rigor and operability of Fuel EAC Eligibility Criteria and accounting approaches.

EACs used to substitute for project fuel usage must meet all of the eligibility criteria in Table 4.

Table 4: Fuel EAC Eligibility Criteria

63.23.2 Calculation Approach

When using EACs to substitute for some, or all, of project fuel usage, the calculation approach described in the following subsections must be followed for the calculation of [math: F_{Fuel}] emissions.

Projects that intend to use EACs for transportation fuel usage and are applying the energy based emission quantification method as in Section 4.2.1 of the GHG Accounting Module) should follow the calculation approach described in Section 6.2.2.1 when using EACs.

Project that intend to use EACs for transportation fuel usage and are applying the distance-based emissions quantification method as in Section 4.2.2 of the GHG Accounting Module should follow the calculation approach described in Section 6.2.2.2 when using EACs.

6.2.2.1 Calculation of Fuel Emissions Using Fuel Environmental Attribute Certificates

When using EACs to substitute for some, or all, of project fuel usage and calculating transportation emissions using the energy usage method, [math: CO_2e_{Fuel}], must be calculated in accordance with Equation 8.

[math: CO_2e_{Fuel,RP} = \sum_j \left[ f_{Fuel} \times \left( m_{j} - m_{EAC,RP} \frac{ED_{EAC,RP}}{ED_{Fuel,RP}} \right) + \left( f_{EAC,RP} \times m_{EAC,RP} \right) \right]]

(Equation 8)

Where:

• [math: m_{j}] = the quantity of fuel consumed, [math: j], in appropriate units, e.g. litres.
• [math: m_{EAC,RP}] = the quantity of fuel represented in EACs used for a Reporting Period, [math: RP], in appropriate units e.g. liters.
• [math: f_{EAC,RP}] = emissions factor of low-carbon fuel represented in EACs used for a Reporting Period, [math: RP], in appropriate units e.g. tonnes of CO2e/liter.
• [math: ED_{EAC,RP}] = energy density of low-carbon fuel represented in EACs used for a Reporting Period, [math: RP], in appropriate units e.g. MJ/liter.
• [math: ED_{Fuel,RP}] = energy density of fuel consumed a Reporting Period, [math: RP], in appropriate units e.g. MJ/liter.

Note, in Equation 8, the term [math: CO_2e_{Fuel}] is analogous to the term [math: CO_2e_{Transportation}] when quantifying transportation emissions using the energy based emission quantification method as in Section 4.2.1 of the GHG Accounting Module.

When applying Equation 8, at maximum, an amount of EACs may be used for a Reporting Period, RP, such that:

[math: \left( m_{j} - m_{EAC,RP} \frac{ED_{EAC,RP}}{ED_{Fuel,RP}} \right) \geq 0]

(Equation 9)

6.2.2.2 Calculation of Transportation Emissions Using Fuel Environmental Attribute Certificates With the Distance-Based Method

Transportation emissions may be calculated using the Distance-Based Method, as set out in Section 4.2.2 of the GHG Accounting Module. When using EACs to substitute for some, or all, of transportation fuel usage and calculating transportation emissions using the distance-based method, the amount of fuel required for each transportation journey, j, must be calculated as:

[math: m_{j} = D_{j} \times W_{j} \times \frac{f_{Transportation,j}}{f_{Fuel,Transportation,j}}]

(Equation 10)

• [math: D_j] = the distance traveled for the transportation journey, [math: j], from one location to another, in appropriate units e.g. km.
• W_j = the mass of material transported as part of the transportation journey, [math: j], from one location to another, in appropriate units e.g. tonnes.
• [math: f_{Transportation,j}] = the weight- and distance -base d emission factor for transportation for a specific vehicle type , or infrastructure asset where available, provided in appropriate units e.g. tonnes of CO2e/tonne-km.
• [math: f_{Fuel,Transportation,j}] = emission factor of fuel assumed to be used for journey j, in appropriate units e.g. tonnes of CO2e/liter. Assumption of fuel type used for journey j as a basis for this calculation must be based either (i) on information provided to The Project Proponent by the transport provider, or (ii) by prevailing fuel type used for the transport mode for journey j in the region of project ope rations, where the most granular or regionally-specific data possible is preferable.

6.3 Acceptable EmissionsEmission Factors - CO₂e_{Fuel, RPR}

[math: f_{fuel,k}] - emissionsEmission factors used must:

• Bebe selected based on the specific fuel type being used and the type of combustion process;
• Be for the specific region (nation, state, locality) where the fuel consumption is occurring, with the most granular or site-specific data source preferred;
• Accountaccount for the full life cycle emissions (well-to-wheel) associated with fuel combustion and include direct emissions (Emissions that are produced by a specific CDR process and are directly controllable.) from fuel combustion, as well as upstream emissions associated with fuel production and equipment manufacture, and downstream emissions associated with equipment decommissioning and disposal, at a minimum.;
• be Where waste heat is used,for the fullmost liferecent cyclepublished emissions factor shall also include transmission and distribution (T&D) losses, where applicableyear; and
• Accountaccount for total GHG emissions as CO₂e, including, at a minimum, CO₂, CH₄, and N₂O emissions. Separate emissionsemission factors for each GHGgas may be utilized and calculated emissions converted to CO₂e using the 100-yr Global Warming Potential (GWP) for the relevant GHG, based on the most recent volumeIPCCUN of100-year theglobal IPCCwarming Assessment Report (presently the Sixth Assessment Report)potentials.

Acceptable emission factors include those utilized in the Argonne National Laboratory GREET Model^{^21}, California Air Resources Board modified GREET model (CA-GREET)^{^32}, Ecoinvent database^{^43}, US Federal Life Cycle Inventory database or LCA Commons^{^54}, and similar databases used in common LCA practices or tools (such as OpenLCA, SimaPro, or GaBi (LCA for Experts) ).

Other emission factors may also be used that do not incorporate the full life cycle emissions associated with fuel combustion if the additional life cycle emissions are accounted for separately. For example, data sources such as the US EPA - Direct Emissions from Stationary Combustion⁶⁷, US EPA AP-42⁷⁸, or US EPA MOVES Model⁸⁹ (mobile sources) may be utilized as long as additional factors for full life cycle emissions are included in analyses.

Note that heat supply to projects from sources other than fuel combustion is allowable under this Module (e.g. geothermal steam). In these cases, bespoke emissions factors are likely necessary on a case-by-case basis, as emissions from such sources can vary significantly by site. Therefore, the exact emissions allocation procedure will be reviewed and agreed by Isometric at the point of project verification.

6

3.43.3 Measurements - CO₂e_{Fuel, RPR}

ThePrimary primary measurementmeasurements considered in calculation of fuel emissions isare:

• [math: m_{fuelFuel,\ k}]: = total mass, volume, or heating value of fuel used for each operation or support system, [math: k] used for a Reporting Period, [math: RP] in appropriate units e.g. kg, gal, ft3, therms.

6

3.53.4 Required Records and& Documentation - CO₂e_{Fuel, RPR}

Fuel usage must be monitored for all operations within the gate at each location of their utilization relevant to project operation. The Projectproject Proponentproponent must maintain records of any fuel use for any operation or support system, [math: k], within the gate of a removal [math: R]'s process, that consumes fuel.

• Allowable fuel records include, but are not limited to:
  • Onon-site fuel meter readings (e.g., natural gas utility meter, fuel flow meters), either electronic or manually logged; or
  • Weightweight of fuel container readings, either electronic or manually logged; or
  • Monthlyalthough not preferable, monthly utility bills may be used, if they indicate total fuel consumptionusage for the month, the bills fully address any fuel usage by the process, and/or a justifiable allocation procedure is used to determine fuel consumption by the process; or
  • Fuelfuel usage for handling equipment may also be determined by any of the above methods, or, if necessary, by documentation of total time of use of each equipment item forduring athe Reporting Period, RP,process and calculation of the fuel consumption based on manufacturer fuel consumption ratings. Data obtained from equipment manufacturer on-board-diagnostics or on board data systems is also acceptable.

If other equipment or processes not related to the removal [math: R]'s process are included in meter readings or utility bills, fuel usage may be allocated to such processes based on sub-metering data, equipment maximum fuel consumption ratings and operating hours for each sub-system and percentage of total maximum fuel consumption accounted for by the meter or utility bill, or by other justifiable allocation methods which must be reviewed and accepted during third party verification.

MetersAny meters used must be calibrated initially and at regular intervals in accordance with manufacturer specifications to ensure accuracy. All records of fuel usage, including meter specificationspecifications and calibration records, must be maintained by Thethe Projectproject Proponentproponent for a period of at least five years.

74.0 Acknowledgements

Isometric would like to thank following contributors to this Modulemodule:

• Tim Hansen (350 Solutions).
• Wilson Ricks (Princeton University)

Isometric would like to thank following reviewers of this module:

• Grant Faber (Carbon Based Consulting).

85.0 Definitions and Acronyms

Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.

The term used to describe greenhouse gas emissions to the atmosphere as a result of Project activities.

Activities that remove carbon dioxide (CO₂) from the atmosphere and store it in products or geological, terrestrial, and oceanic Reservoirs. CDR includes the enhancement of biological or geochemical sinks and direct air capture (DAC) and storage, but excludes natural CO₂ uptake not directly caused by human intervention.

An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.

Those gaseous constituents of the atmosphere, both natural and anthropogenic (human-caused), that absorb and emit radiation at specific wavelengths within the spectrum of terrestrial radiation emitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).

A collection of Removal or Reduction processes that have mechanisms in common.

An estimate of the emissions intensity per unit of an activity.

Any person or entity who can potentially affect or be affected by Isometric or an individual Project activity.

Any process or activity that releases a greenhouse gas, an aerosol, or a precursor of a greenhouse gas into the atmosphere.

Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.

Raw material which is used for CO₂ Removal or GHG Reduction.

The amount of CO₂ emissions that would cause the same integrated radiative forcing or temperature change, over a given time horizon, as an emitted amount of GHG or a mixture of GHGs. One common metric of CO₂e is the 100-year Global Warming Potential.

The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.

A collection of Removal or Reduction processes that have mechanisms in common.

The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.

GHG sources, sinks and reservoirs (SSRs) associated with the project boundary and included in the GHG Statement.

The increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities.

A geographically precise and internally well-connected energy distribution and use area representing a subsection or the entirety of a synchronized electricity grid. The assignment of a project to a grid region should be based on the location of the project’s point of interconnection within the topology of the electricity system, rather than the physical location of the project itself.

AThe publiclyanalysis visibleof uniquelyspecific identifiableUncertainties, Credithazards Certificateand Issuedscenarios byinherent ain Registrycomplex thatsystems givessuch as the ownernatural and engineered environment, aiming to describe how systems-level environmentally relevant flows will change in response to possible decisions.

Those gaseous constituents of the Creditatmosphere, both natural and anthropogenic (human-caused), that absorb and emit radiation at specific wavelengths within the rightspectrum toof accountterrestrial forradiation oneemitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).

Purposefully erring on the side of caution under conditions of Uncertainty by choosing input parameter values that will result in a lower net metric tonne of Verified CO₂e Removal or GHG Reduction. Inthan if using the casemedian ofinput thisvalues. Standard,This is done to increase the netlikelihood tonnethat ofa CO₂egiven Removal or Reduction comes from a Project Validated against a Certified Protocol.

A contract in which a Buyer agrees to purchase a set Removal and/or Reduction at a set price.

A process for evaluating and confirming the net Removals and Reductions for a Project, using data and information collected from the Project and assessing conformity with the criteria set forth in the Isometric Standard and the Protocol by which itcalculation is governed.an Verificationunderestimation mustrather be completed bythan an Isometric approved third-party (VVB)overestimation.

The documentestimated change in total greenhouse gas emissions from a structurally-fixed electricity system that clearlywould outlinesresult howfrom an incremental change in electricity demand at a Projectspecific willpoint generatein rigorouslythe quantifiablesystem Additionalat higha specific time. Short-qualityrun Removalsmarginal emissions rates reflect the emissions associated with real-time changes in output from specific marginal generators in response to the hypothetical change in demand. They do not reflect the potential for a persistent change in demand to incentivize entry of new generating facilities into the electricity system (i.e., structural change). Multiple methodologies for calculating short-run marginal emissions rates from available grid data exist, but all aim to quantify the same impact. Short-run marginal emissions rates are provided directly at hourly or Reductionssub-hourly resolution by some grid operators, and in other cases they are calculated and made available by third-party vendors. Some grid operators also provide temporally granular data on ‘fuels on the margin,’ from which project proponents may calculate marginal emissions rates using average fuel-specific emissions factors from the grid region in question.

ALife systematiccycle GHG emissions associated with production of materials, transportation, and independentconstruction processor other processes for evaluatinggoods theor reasonablenessbuildings.

An estimate of the assumptions,emissions limitationsintensity andper methodsunit that support a Project and assessing whether the Project conforms to the criteria set forth in the Isometric Standard and the Protocol by which the Project is governed. Validation must be completed byof an Isometric approved third-party (VVB)activity.

A measure of how much energy the emissions of 1 tonne of a GHG will absorb over a given period of time, relative to the emissions of 1 ton of CO₂.

An analysis of the balance of positive and negative emissions associated with a certain process, which includes all of the flows of CO₂ and other GHGs, along with other environmental or social impacts of concern.

A United States Government agency that protects human health and the environment.

Sources, Sinks and Reservoirs

An evaluationset of thedata likelihooddescribing that an intervention—for example, a CDR Project—causes a climate benefit above and beyond what would have happened in a nopre-intervention Baselineor scenario.

9.0control Appendix A - Companion Documentation

This appendix is a companionconditions to the Energy Use Accounting Module, providing supporting information regarding the rationale and factors considered when determining the requirements of the Module. This appendix should be read in conjunction with the Module and is provided as guidance. Should there be any discrepancy or inconsistency between this appendix and the Module itself, the requirements of the Module will prevail.

9.1 Why Does the Module Use Average Emissions Factors for Grid-Based Electricity Use?

The emissions accounting approach adopted in this Module for electricity consumption from the grid requires the use of grid-average emissions factors. An alternative approach supported by some published studies relies on the use of marginal emissions factors when accounting for emissions from electricity consumption from the grid.

Marginal emission factors represent the change in emissions resulting from a marginal change in electricity demand or supply on the grid. Marginal emission factors vary by time horizon and scope and include Short-run marginal emissions (SRME) factors and Long-run marginal emission (LRME). Isometric acknowledges that marginal emission factors are the most conceptually aligned approach with a consequential emissions accounting framework for CDR projects; however, the implementation of marginal emission factors (SRME, LRME, or both) has not reached a consensus in CDR project accounting.

Brander et al. (2025)9 caution that SRME factors, which are the most commonly available marginal metrics, should not be used as a proxyreference scenario for comparison.