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Energy Use Accounting
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This module (Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.) describes how energy-related emissions must be calculated in a carbon removal project (An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.) so that 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.
[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}].
Refer to Transportation Emissions Accounting Module for the calculation guidelines.
Where possible, project proponents (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 3.2.21.
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_{Electricity,\ R}] and [math: CO_2e_{Fuel,\ 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.
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].
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, [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].
The two categories of projectprojects relevant to this calculation approach are intensive facilitiesprojects, 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 3.2.23. 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 3.2.12. All projects may by default categorize their facilities as non-intensive unless otherwise specified in the relevant protocol (A document that describes how to quantitatively assess the net amount of CO₂ removed by a process. To Isometric, a Protocol is specific to a Project Proponent's process and comprised of Modules representing the Carbon Fluxes involved in the CDR process. A Protocol measures the full carbon impact of a process against the Baseline of it not occurring.).
The following calculation approach must be followed for non-intensive projectsfacilities:
[math: CO_2e_{Electricity,\ R} =\sum_{1}^{N}kwh_{k}\cdot EF_{Elect,\ r}]
(Equation 2)
Where:
If a project relying on a non-intensive projectfacility wishes to reduce their energy emissions through the purchase of qualifying electricity then they may use Equations 3 and 4 replacing [math: EF_G] with [math: 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 (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.
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, [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,\ 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:
Electricity consumption may be subdivided into consumption of 'Qualified' electricity and 'non-Qualified' electricity:
AllTo be 'Qualified', electricity ismust deemed 'non-Qualified' unless it meetsmeet all of the following eligibility criteria below:
| Eligibility Criteria | Documentation required | |
|---|---|---|
| EC1 | The electricity utilized is renewable energy via self generation or via
contract purchase | Physical system documentation, including capacity, location, and ownership for on-site generation. For contracted generation either:
|
Or if all of the following criteria (EC2 - EC5) are true:
| EC2 | The Project has acquired and retired all RECs or similar EACs associated with the claimed electricity, except those that are transferred to a load-serving entity to meet the requirements of a jurisdictional clean electricity standard (CES) or similar government policy, and must submit sufficient proof that this has occurred. In jurisdictions where a CES or similar government policy requires the Project’s load-serving entity to retire EACs in an amount representing some percentage of the Project’s total electricity consumption, the Project may transfer EACs in this amount to the relevant load-serving entity while simultaneously using these to claim qualifying electricity consumption under this Protocol. These transfers may not exceed the amount by which the load-serving entity’s legal EAC retirement obligation has increased as a result of the Project’s electricity consumption. | If the Project has
If the Project has
|
| EC3 | The generating facility from which the claimed electricity is sourced entered service no more than 24 months before the Project. If the project is located within the service territory of a vertically-integrated electric utility or state energy company that does not permit customers to procure power directly, utility programs that pair commercial and industrial customers with specific new clean energy developments can be a suitable alternative to direct bilateral contracts. Ideally, any long-term offtake will have been arranged before the generating facility enters an interconnection queue or equivalent regional process. | In all cases, the Project must provide:
If the Project has
|
| EC4 | The electricity must be generated in the same hour for which it is claimed. | The Project must provide hourly-granularity electricity consumption data collected via on-site metering, in addition to one of the following:
|
| EC5 | The electricity must be physically deliverable to the project in the same hour for which it is claimed. Electricity is to be considered physically deliverable if any of the following conditions are met:
| In all cases, the Project must provide:
In cases where the Project is not directly connected ‘behind the meter’ to the generating facility, the Project must provide:
In cases where the Project seeks to establish deliverability between two adjacent grid regions, the Project must provide:
|
Emission factors (An estimate of the emissions intensity per unit of an activity.) used must:
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 (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) ).
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, [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:
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.
Emission rates must not:
For every generating facility, [math: p], the value of [math: G_{p}] (see Section 3.2.23) 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.
Primary measurements considered in calculation of electricity emissions are:
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, [math: k], within the gate of a removal, [math: R]'s, process, that consumes electricity. This is in addition to documentation listed in Section 3.2.34, if applicable to a project.
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 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.
[math: CO_2e_{Fuel,\ R} =\sum_{1}^{k} m_{Fuel,\ k}\cdot\ EF_{Fuel}]
(Equation 5)
Where:
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:
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.
Refer to Embodied Emissions Accounting Module for the calculation guidelines.
Waste heat utilization must meet all the following criteria to be considered true waste heat, and be exempt from GHG emissions accounting:
| Eligibility Criteria | Documentation Required | |
|---|---|---|
| EC6 | Heat is provided from an off-site source | Documentation of the waste heat provision, including:
|
| EC7 | The end-user does not pay for the heat, or only pays for costs associated with the delivery of the heat, such as pipeline construction, or any energy costs associated with delivery, such as pump operation | See EC6 requirements. A cost structure for the contract purchase price must be provided. This may be a breakdown of contract price by heat provider OR may be an estimate of the waste heat pricing and delivery costs based on the specific contract, equipment, and heat source. |
| EC8 | The waste heat is ‘unavoidable waste heat or cold,’ requiring that the thermal energy cannot:
| One of the following:
|
| EC9 | Waste heat or cold must be a byproduct of an operation or process (heat or cold is not the intended output of a processes, such as in a combined heat and power facility) | Copy of contract and information required as indicated in EC6 |
Emission factors used must:
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:
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, [math: k], within the gate of a removal [math: R]'s process, that consumes fuel.
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.
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:
Isometric would like to thank following reviewers of this module:
The accounting approach outlined in Section 3.2.23 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 3.2.34 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 1011. 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 (Lowering future GHG releases from a specific entity.) 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:
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.
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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
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