Energy Use Accounting

This module describes how energy-related emissions must be calculated in a carbon removal project so that they can be subtracted in the net CO₂e removal calculation. Furthermore, this module applies to all carbon removal pathways, ensuring a consistently rigorous standard in how energy-related emissions are quantified and reported between different carbon removal projects and approaches.

$CO_2e_{Energy\ R}$ 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 $k$.

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 $k$, such as electric or diesel vehicles, as they are accounted for in $CO_2e_{Transportation,\ R}$.

Where possible, project proponents should account for emission impacts of electricity usage based on the same grid regions (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 emission impacts of electricity usage may also be required. More details on when this is applicable can be found in Section 3.2.1.

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

$$CO_2e_{Energy,\ R} = CO_2e_{Electricity,\ R} + CO_2e_{Fuel,\ R}$$

(Equation 1)

Where:

• $CO_2e_{Energy,\ R}$ = the total quantity of GHG emissions (mass units of CO₂e, including, at a minimum, CO₂, CH₄, and N₂O emissions) associated with energy consumption for a removal, $R$, in tonnes;
• $CO_2e_{Electricity,\ R}$ = Emissions from electricity usage for a removal, $R$, in tonnes, see Section 3.2; and
• $CO_2e_{Fuel,\ R}$ = Emissions from fuel combustion to produce heat or thermal energy in the process or from fuel combustion in primarily non-road mobile equipment, such as forklifts and other material handling equipment used within the process (inside the gate), for a removal, $R$, in tonnes, see Section 3.3, Equation (5).

$CO_2e_{Electricity,\ R}$ and $CO_2e_{Fuel,\ R}$ must account for operations and support systems that consume electricity or fuel within a removal, denoted as $k$. 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, $k$, are accounted for.

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

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.

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

The two categories of projects relevant to this calculation approach are intensive projects, which have the potential for significant amounts of electricity utilization, and non-intensive projects. A facility is considered to be non-intensive for the purposes of a project if it uses less than 10 GWh and where the estimated electricity use per ton of CO₂ sequestration is less than 50 kWh. Facilities that use greater than 10 GWh of electricity or where estimated electricity use per ton of CO₂ sequestration is greater than 50 kWh are classified as intensive facilities.

Any intensive facilities within a project, such as direct air capture facilities, must evaluate and account 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.

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

$$CO_2e_{Electricity,\ R} =\sum_{1}^{N}kwh_{k}\cdot EF_{Elect,\ r}$$

(Equation 2)

Where:

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

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 4 replacing $EF_G$ with $EF_{Elect,\ r}$. Project proponents will be responsible for collecting sufficient documentation to submit these calculations.

For intensive facilities a consequential accounting approach is adopted (see Appendix 1 for further information), which is designed to be conservative 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.

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.

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

$$CO_2e_{Electricity,\ R} = \sum CO_2e_{Electricity,\ L}$$

(Equation 3)

Where:

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

$CO_2e_{Electricity,\ L}$ is calculated as follows:

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

(Equation 4)

Where:

• $kwh_{L}$ = total kilowatt-hours of electricity consumption in the hour in question;
• $G_{p}$ = the amount of qualifying electricity procured for physical delivery from generator, $p$, to the project in the same hour;
• $m_p$ = derating factor used to account for transmission losses from delivery of power from generator, $p$;
• $EF_G$ = the hourly short-run marginal emissions rate (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;
• $EF_{p}$ = the hourly average carbon dioxide equivalent emissions intensity of the electricity generated by generator $p$.

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
• ‘non-Qualified’ electricity requires accounting for consequential impacts of the electricity use on emissions from the entire grid via hourly marginal emissions analysis

To be 'Qualified', electricity must meet all of the following eligibility criteria:

Emission factors used must:

• be technology-specific to the method of electricity generation;
• account 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;
• be for the specific region (nation, state, locality) where the electricity production occurring, with the most granular or site-specific data source preferred;
• be for the most recent published year; and
• account for total GHG emissions as CO₂e. Separate emission factors for each GHG may be utilized and calculated emissions converted to CO₂e based on most recent IPCCUN 100-year global warming potentials.

Acceptable emission factors include those utilized in the Argonne National Laboratory GREET Model¹, California Air Resources Board modified GREET model (CA-GREET)², Ecoinvent database³, US Federal Life Cycle Inventory database or LCA Commons⁴, 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 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 (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.

Project proponents may estimate the short-run marginal emissions (SRME) rate, $EF_G$, 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 $EF_G$ do not incorporate upstream emissions, the project proponent should apply a 1.2x mulitplier to the baseline 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 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 $EF_G$ 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 $EF_G$ SRME data from grid regions other than the one in which the project is located.

For every generating facility, $p$, the value of $G_{p}$ (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 $m_{p}$ should be equal to 1. If the generating facility is not co-located with the Project, the value of $m_{p}$ should be revised to 0.95, in order to account for transmission losses⁶.

Primary measurements considered in calculation of electricity emissions are:

• for non-intensive facilities:
  • $kwh_k$ (Equation 2) - total kilowatt hours of electricity used for each operation or support system, $k$; and
• for intensive facilities:
  • $kwh_L$ (Equation 4) - total kilowatt hours of electricity used for the hour in question

Measurements must be made using utility grade power metering with hourly reporting at a minimum. Meters must have an accuracy of better than 2% of reading for total energy consumption as reported in kwh.

Any meters used must be calibrated initially and at regular intervals in accordance with manufacturer specifications.

Electricity usage must be monitored for all operations within the gate at each location of their utilization relevant to project operation. The project proponent must maintain records of any electricity use for any operation or support system, $k$, within the gate of a removal, $R$'s, process, that consumes electricity. This is in addition to documentation listed in Section 3.2.4, if applicable to a project.

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

If other equipment or processes not related to the removal, $R$’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 specifications and calibration records, must be maintained by the project proponent for a period of five years.

Process emissions may result from combustion of fuels to provide thermal energy to support equipment startup and operation or to supply steam or other thermal energy sources for operations.

$$CO_2e_{Fuel,\ R} =\sum_{1}^{k} m_{Fuel,\ k}\cdot\ EF_{Fuel}$$

(Equation 5)

Where:

• $CO_2e_{Fuel,\ R}$ = total GHG emissions resulting from thermal energy generation via fuel combustion for a removal $R$, in tonnes of $CO_2e$
• $m_{Fuel,\ k}$ = total mass, volume, or heating value of fuel used for each operation or support system, $k$, as part of a removal, $R$ (kg, gal, ft³, therms, etc. as required based on emission factor units)
• $EF_{Fuel}$= Emission factor in tonnes $CO_2e$/unit for a given fuel type where unit is specific to each fuel type and factor

Operations may consider the use of waste heat to potentially reduce the energy usage of a process. A true waste heat source does not require accounting of GHG emissions associated with the production and delivery of the waste heat to the project gate. Waste heat utilization must meet the criteria in Section 3.3.1 to be considered waste heat.

Any activities specifically developed inside the project gate to handle and utilize the waste heat, however, must be accounted for in the life cycle analysis. These potentially include:

• waste heat distribution systems, including pumps, piping, or other equipment
• waste heat upgrading processes, such as heat pumps, booster pumps, or other
• waste heat conversion processes, such as waste heat to power technologies, such as organic ranking cycle generators

Equipment and energy usage associated with waste heat utilization must be accounted for in accordance with the requirements of this module and the Embodied Emissions module.

Waste heat utilization must meet all the following criteria to be considered true waste heat, and be exempt from GHG emissions accounting:

Emission factors used must:

• be selected based on the specific fuel type being used and the type of combustion process;
• account for the full life cycle emissions (well-to-wheel) associated with fuel combustion and include direct emissions 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 for the most recent published year; and
• account for total GHG emissions as CO₂e, including, at a minimum, CO₂, CH₄, and N₂O emissions. Separate emission factors for each gas may be utilized and calculated emissions converted to CO₂e based on most recent IPCCUN 100-year global warming potentials.

Acceptable emission factors include those utilized in the Argonne National Laboratory GREET Model¹, California Air Resources Board modified GREET model (CA-GREET)², Ecoinvent database³, US Federal Life Cycle Inventory database or LCA Commons⁴, 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 Combustion⁷, US EPA AP-42⁸, or US EPA MOVES Model⁹ (mobile sources) may be utilized as long as additional factors for full life cycle emissions are included in analyses.

Primary measurements considered in calculation of emissions are:

• $m_{Fuel,\ k}$ = total mass, volume, or heating value of fuel used for each operation or support system, $k$

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

• Allowable fuel records include, but are not limited to:
  • on-site fuel meter readings (e.g., natural gas utility meter, fuel flow meters), either electronic or manually logged
  • weight of fuel container readings, either electronic or manually logged
  • although not preferable, monthly utility bills may be used, if they indicate total fuel usage for the month, the bills fully address any fuel usage by the process and a justifiable allocation procedure
  • fuel 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 during the process and calculation of 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 $R$'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.

Any meters used must be calibrated initially and at regular intervals in accordance with manufacturer specifications. All records of fuel usage, including meter specifications and calibration records, must be maintained by the project proponent for a period of five years.

Isometric would like to thank following contributors to this module:

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

Isometric would like to thank following reviewers of this module:

• Grant Faber (Carbon Based Consulting).

The accounting approach outlined in Section 3.2.3 implicitly assumes that all non-differentiated grid electricity generated to supply a Project’s needs comes from existing marginal generators, which in today’s electricity systems are generally fossil-fired. This method on its own is likely to overestimate the long-run marginal emissions impact of a plant’s electricity consumption, as it is possible if not likely that new low-carbon generators would eventually be deployed to meet some portion of this demand.

Because the consequential impact of a Project's electricity consumption on decisions to deploy new low-carbon generators cannot be observed empirically, the approach endorsed in Section 3.2.4 requires that a Project procure power directly from new low-carbon generators in order to be credited with consumption of their electricity. It further requires procured electricity to be generated in the same hourly period for which it is claimed, and to be physically deliverable to the Project during this period. These conditions align the electricity market and emissions impacts of both grid-based generators and those that are co-located with the Project.

While recent research has demonstrated that procurement of carbon-free electricity subject to these constraints can typically mitigate the consequential emissions impact of a Project’s electricity consumption during the hours for which such claims are made, there are still conditions under which this mitigation can be imperfect ^{10 11}. If low-carbon energy deployment is constrained temporarily by manufacturing, permitting, or installation bottlenecks, or permanently by geographic limitations, there can be carbon opportunity costs associated with the procurement of these resources to serve new electricity demand rather than to displace existing fossil-fired electricity generation. While this module establishes guardrails intended to mitigate such outcomes, it should be acknowledged that these carbon opportunity costs are fundamentally unobservable and cannot be eliminated with certainty. Project developers should take steps to qualitatively assess current and potential future bottlenecks to clean electricity development in their target markets, and should aim to deploy projects in locations where such constraints are minimized.

Binding government-imposed caps on GHG emissions prevent individual electricity consumers from driving system-level changes in emissions, and thereby obviate the need for project-level accounting of consequential emission impacts.

In a jurisdiction subject to a robust GHG cap-and-trade policy that is not oversupplied with emissions allowances, any increases in emissions from a project’s electricity consumption are required to be offset by reductions in emissions elsewhere in the economy. Therefore, the consequential emissions impact of a project’s electricity consumption should be assumed to be 0, if the project is located in an approved jurisdiction with a GHG cap-and-trade policy recognized under this Protocol as sufficiently robust.

Factors that characterize a robust cap-and-trade policy include:

• emission limits that are stringent in relation to emissions, inclusive of any banked compliance instruments,
• effective border adjustment policies that minimize carbon leakage, especially in the electricity sector,
• the legal authority and apparent political commitment to operate the market over long time horizons, and
• any other major factors that illustrate a high likelihood of credible, binding emission limits for covered facilities.

Currently the EU Emissions Trading Scheme, which covers the 27 EU member nations as well as Iceland, Norway, and Liechtenstein, is the only cap-and-trade jurisdiction approved as sufficiently rigorous under this Protocol.

EcoInvent. (2013). Overview and methodology Data quality guideline for the ecoinvent database version 3. https://ecoinvent.org/wp-content/uploads/2020/10/dataqualityguideline_ecoinvent_3_20130506_.pdf

Intergovernmental Panel on Climate Change (IPCC). (2023). IPCC Sixth Assessment Report. https://www.ipcc.ch/assessment-report/ar6/

International Organization for Standardization. (2006). ISO 14040:2006 Environmental management — Life cycle assessment — Principles and framework. https://www.iso.org/standard/37456.html

International Organization for Standardization. (2006). ISO 14044:2006 Environmental management — Life cycle assessment — Requirements and guidelines. https://www.iso.org/standard/38498.html

International Organization for Standardization. (2008). Evaluation of measurement data — Guide to the expression of uncertainty in measurement (ISO JGCM GUM). https://www.iso.org/sites/JCGM/GUM/JCGM100/C045315e-html/C045315e.html?csnumber=50461

International Organization for Standardization. (2011). ISO 14066:2011 Greenhouse gases — Competence requirements for greenhouse gas vion teams and verification teams. https://www.iso.org/standard/43277.html

International Organization for Standardization. (2017). ISO 21930:2017 Sustainability in buildings and civil engineering works — Core rules for environmental product declarations of construction products and services. https://www.iso.org/standard/61694.html

International Organization for Standardization. (2017). ISO/IEC 17025:2017 General requirements for the competence of testing and calibration laboratories. https://www.iso.org/standard/66912.html

International Organization for Standardization. (2019). ISO 14064-2:2019. Greenhouse Gases - Part 2: Specification With Guidance At The Project Level For Quantification, Monitoring And Reporting Of Greenhouse Gas Emission Reductions Or Removal Enhancements. ISO. https://www.iso.org/standard/66454.html

International Organization for Standardization. (2019). ISO 14064-3:2019. Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements. ISO. https://www.iso.org/standard/66455.html

Isometric. (n.d.). Isometric — Glossary: Defining the terms that appear regularly in our work. Isometric. https://isometric.com/glossary

Matthews, J.B.R. (Ed.). (2018). IPCC, 2018: Annex I: Glossary [Matthews, J.B.R. (ed.)]. In: Global Warming of 1.5°C. An IPCC Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of... Cambridge University Press. https://doi.org/10.1017/9781009157940.008

U.S. Environmental Protection Agency. (2023, April 18). Understanding Global Warming Potentials | US EPA. Environmental Protection Agency. Retrieved June 14, 2023, from https://www.epa.gov/ghgemissions/understanding-global-warming-potentials

1. https://greet.es.anl.gov/ ↩ ↩²

2. https://ww2.arb.ca.gov/resources/documents/lcfs-life-cycle-analysis-models-and-documentation ↩ ↩²

3. https://ecoinvent.org/ ↩ ↩²

4. https://www.lcacommons.gov/ ↩ ↩²

5. https://app.electricitymaps.com/map,https://www.watttime.org/, https://www.caiso.com/todaysoutlook/Pages/emissions.html ↩

6. https://www.eia.gov/tools/faqs/faq.php?id=105&t=3 ↩

7. https://www.epa.gov/sites/default/files/2016-03/documents/stationaryemissions_3_2016.pdf ↩

8. https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors ↩

9. https://www.epa.gov/moves ↩

10. https://iopscience.iop.org/article/10.1088/1748-9326/acacb5 ↩

11. https://zenodo.org/doi/10.5281/zenodo.8325963 ↩