PCS TR 006 Geothermal Power Methodology_v1.0

Document Control

Document identification

• Document code: PCS-TR-006

• Title: Geothermal Power Methodology

• Scope: Defines applicability conditions, project boundary rules, baseline determination and baseline emissions calculation, additionality requirements, monitoring requirements, leakage treatment, and net emission reduction calculation procedures for PCS geothermal electricity generation projects that deliver electricity and claim emission reductions through displacement of electricity generation.

Version history and change log

Table DC-1. Revision history

Version	Date	Status	Summary of changes	Prepared by	Approved by
v1.0	TBD	Draft	Release for public consultation	PCS	TBD

Superseded versions

No superseded versions for v1.0.

Governance note on versioning and archiving

Only the latest approved version of this Methodology shall be used. Superseded versions shall be archived and retained for traceability and audit purposes. Printed or downloaded copies are uncontrolled; stakeholders must refer to the PCS-published version as the authoritative current version.

Chapter 1 - Purpose

1.1 Purpose

This methodology establishes the activity-specific requirements for quantifying emission reductions from geothermal electricity generation under the Planetary Carbon Standard (PCS). It defines applicability conditions, baseline determination requirements, monitoring requirements, and calculation boundaries for geothermal power projects.

1.2 Intended use

This methodology shall be applied to geothermal electricity generation projects seeking issuance of PCS units for measurable and verifiable displacement of electricity generation that would otherwise occur in the absence of the project activity. The methodology shall be implemented as written and supported by auditable records sufficient for validation and verification.

1.3 Relationship to other PCS documents

This methodology shall be applied together with PCS standards, any methodological tools referenced by this methodology, and the approved PCS templates and forms used for project submission and reporting. In the event of inconsistencies, higher-order PCS documents prevail.

1.4 Binding nature

Requirements expressed using “shall” are mandatory. Where this methodology references a methodological tool, that tool shall be applied as specified. Templates and forms required by PCS shall be used without substitution unless an explicit exception is granted through the PCS deviation process.

1.5 Version control and applicability

This methodology is subject to controlled versioning. The applicable version is the version in force at the time of project submission unless transition provisions specify otherwise. Revisions follow PCS governance procedures and do not apply until they enter into force.

Chapter 2 - Scope and Applicability

2.1 Scope

This methodology applies to projects that generate electricity using geothermal resources and demonstrate measurable displacement of electricity generation that would otherwise occur in the absence of the project.

Geothermal projects may have non-negligible project emissions due to release of non-condensable gases (including CO₂) from geothermal fluids and due to auxiliary fossil fuel use where applicable. Applicability under this methodology is therefore conditional on the project’s ability to monitor and account for relevant project emissions conservatively and verifiably.

2.2 Eligible project types

A project is eligible under this methodology where the project activity consists of installation and operation of geothermal power facilities and associated infrastructure that generate electricity and deliver electricity to an eligible electricity system.

Eligible project types include, subject to the conditions in this chapter:

2.2.1 New geothermal power plant

New geothermal facilities generating electricity and exporting to a grid or supplying a defined captive system are eligible, provided project emissions can be monitored and accounted for.

2.2.2 Expansion or capacity addition

Expansions are eligible where the additional capacity and generation can be clearly separated from pre-existing operations for baseline setting and monitoring and where the project proponent prevents double counting between phases.

2.2.3 Efficiency improvement and retrofits

Projects that increase net electricity output of an existing geothermal facility through efficiency improvements or retrofits are eligible where the incremental generation and any associated changes in project emissions can be quantified and monitored.

2.2.4 Geothermal with reinjection and abatement

Projects that reinject geothermal fluids and/or apply abatement technologies for non-condensable gases are eligible, provided the monitoring system can demonstrate the effectiveness and permanence of the abatement in a verifiable manner.

2.3 Applicable delivery configurations

Table 2-1. Applicability by delivery configuration

Configuration	Applicability under this methodology	Minimum conditions that shall be met
Grid-connected export	Applicable	Net electricity exported shall be metered; the connected grid/system shall be identified; baseline EF approach shall be justified and consistently applied; project emissions shall be monitored where applicable.
Captive/on-site displacement (fossil generation)	Applicable	Baseline supply shall be evidenced; displacement demonstrated through metered delivery; project emissions from geothermal gases and auxiliary fossil use shall be accounted where applicable.
Mixed grid export and captive supply	Applicable	Electricity quantities shall be separately accounted; double counting prevented; route-specific baseline EF applied consistently.
Electricity used primarily for fuel production (e.g., hydrogen/e-fuels)	Not applicable	Not eligible unless PCS issues a dedicated methodology.

2.4 Exclusions and non-applicable cases

This methodology shall not be applied to:

1. Projects where electricity generation or delivery cannot be reliably metered and audited.

2. Projects where geothermal gas emissions are expected to be material but cannot be monitored and conservatively quantified.

3. Projects where the baseline scenario cannot be credibly and conservatively established.

4. Projects that seek crediting for heat-only applications (direct-use geothermal) unless PCS issues a dedicated heat methodology.

5. Projects involving hybrid systems where geothermal attribution cannot be separated and conservatively quantified under this methodology.

2.5 Applicability conditions

A project shall be applicable only where all conditions below are satisfied.

2.5.1 Demonstrable displacement

The project shall demonstrate that electricity generated and delivered results in displacement of electricity generation that would otherwise occur.

2.5.2 Boundary consistency

Project and baseline boundaries shall be consistent and complete for quantification. Any boundary difference shall be justified and shall not increase credited reductions.

2.5.3 Geothermal emissions applicability screening

The project proponent shall assess whether geothermal gas emissions are relevant and material. Where relevant, geothermal gas emissions shall be quantified as project emissions and monitored.

If geothermal gas emissions cannot be quantified conservatively and verifiably, the methodology shall be deemed not applicable.

2.5.4 Monitoring feasibility

The project shall have a monitoring system capable of producing auditable records for net electricity delivered, baseline emission factor application, and all project emissions required under this methodology.

Chapter 3 - Conditions for Eligibility

3.1 General eligibility requirement

A project shall be eligible under this methodology only where it is demonstrably within scope, meets all applicability conditions, and can be validated and verified using auditable records. A project shall not proceed to registration where the methodology is not fully applicable or where required evidence cannot be produced in a verifiable form.

3.2 Project activity eligibility

The project activity shall consist of installation and operation of geothermal power equipment and associated infrastructure that generates electricity from geothermal resources and delivers electricity to an eligible electricity system as defined in Chapter 2.

The project shall identify whether it is a new plant, an expansion, an efficiency improvement, or an abatement/reinjection configuration. Where the project includes multiple units or phases, the project proponent shall demonstrate separability of the credited activity and shall prevent double counting across phases or units.

3.3 Legal compliance and permits

The project shall comply with all applicable laws and regulations. The project proponent shall demonstrate that all material permits and approvals required for geothermal exploration and drilling, resource use, environmental clearance, reinjection, air emissions compliance, land access, and grid interconnection have been obtained and are valid at the time of registration.

Where approvals are conditional or phased, the project proponent shall demonstrate that conditions relevant to the credited activity and monitoring system are satisfied prior to the start of the crediting period.

3.4 Right to claim emission reductions and avoidance of double counting

The project proponent shall demonstrate legal authority and contractual rights to claim the emission reductions resulting from the project activity. The project shall not claim emission reductions that are already claimed or used under another program, instrument, or mechanism unless an explicit and verifiable non-overlap arrangement exists and is consistent with PCS requirements on double counting.

Where power purchase agreements, wheeling arrangements, concessions, joint ventures, or public-private ownership exist, the project proponent shall document attribute ownership and demonstrate that mitigation outcomes are not claimed elsewhere.

Where host-country authorization and corresponding adjustment requirements apply to the intended use of the credits, the project proponent shall demonstrate alignment with the applicable PCS authorization requirements.

3.5 Start date and prior consideration

The project shall define a clear project start date. Where required by PCS rules, the project proponent shall demonstrate prior consideration of carbon finance through contemporaneous evidence. Absence of credible contemporaneous evidence, where required, shall render the project ineligible.

3.6 Baseline eligibility and boundary consistency

The project shall identify a credible baseline scenario consistent with this methodology. The baseline scenario shall not be defined in a manner that inflates emission reductions. Project and baseline boundaries shall be consistent for all emission sources relevant to quantification. Any boundary difference shall be explicitly justified and shall not increase credited emission reductions.

3.7 Additionality eligibility

The project shall demonstrate additionality in accordance with PCS requirements and this methodology. The project shall not be eligible where the project activity is legally mandated or otherwise non-additional under PCS rules.

3.8 Geothermal gas emissions eligibility requirement

Geothermal power projects may emit non-condensable gases. Eligibility under this methodology is conditional on conservative and verifiable accounting of project emissions.

1. The project proponent shall assess whether CO₂ emissions from geothermal fluids are relevant and material for the project. Where relevant, such emissions shall be quantified as project emissions for each monitoring period.

2. If the project includes abatement (e.g., gas capture, reinjection, mineralization) or claims reduced emissions due to reinjection, the project shall monitor and demonstrate performance of the abatement system using auditable records. Claims shall not rely on assumed abatement efficiency without evidence.

3. Where the project discharges geothermal gases to atmosphere and emissions are expected to be material, the project shall measure or conservatively quantify emissions using a method suitable for validation and verification.

4. If geothermal gas emissions cannot be quantified conservatively and verifiably, the project shall be deemed not eligible for issuance for the affected periods, and may be deemed not eligible for registration where feasibility cannot be demonstrated at validation.

3.9 Monitoring system eligibility

A project shall be eligible only where it has a monitoring system capable of producing complete and auditable records for all parameters required under this methodology. At minimum, the monitoring system shall be capable of producing verifiable records of net electricity delivered and geothermal gas emissions parameters (where applicable), as well as any fossil backup generation parameters.

If the monitoring system is not capable of meeting these requirements at validation, the project shall not be eligible for registration under this methodology.

3.10 Treatment of material changes

The project proponent shall disclose any material change to project design, wells and fluid handling, reinjection or abatement configuration, delivery configuration, ownership, metering arrangement, or operational control that may affect applicability, baseline, additionality, monitoring, or quantification.

Where a material change occurs, the project proponent shall apply PCS procedures for post-registration changes and shall obtain approval where required prior to claiming credits for the affected period.

3.11 Specific exclusion triggers

A project shall be deemed not eligible under this methodology where any of the following apply:

1. Net electricity delivery cannot be demonstrated through auditable metering and records.

2. The baseline scenario cannot be credibly established or relies on assumptions that materially increase credited reductions without evidence.

3. Geothermal gas emissions are relevant and potentially material but are not quantified and monitored conservatively and verifiably.

4. Abatement/reinjection claims are made without measurable evidence and auditable performance records.

5. Double counting risk exists due to unclear ownership, overlapping programs, or conflicting claims.

3.12 Eligibility evidence requirements

Eligibility shall be supported by documentary evidence sufficient for validation and verification. Evidence shall be traceable, dated where relevant, and auditable.

Table 3-1. Minimum eligibility evidence (non-exhaustive)

Eligibility area	Minimum evidence to be provided
Project description and configuration	Technical description, process flow diagrams, equipment lists, commissioning records
Permits and resource rights	Geothermal licenses, drilling approvals, reinjection permits, environmental approvals, air emissions permits
Grid interconnection / delivery	Interconnection agreements, export meters, wheeling documents where applicable
Right to claim / non-overlap	Contracts (PPA/concession/JV), attribute ownership clauses, non-overlap declarations
Start date / prior consideration (if required)	Investment decision documents, financing documents, contemporaneous communications
Baseline and boundary	Baseline scenario description, boundary diagrams, justification of inclusions/exclusions
Additionality	Regulatory analysis, investment/barrier analysis, common practice assessment
Geothermal gas emissions	Gas composition tests, flow/venting records, abatement system design and performance records, monitoring plan
Monitoring feasibility	Meter specs, calibration plan/records, data management procedures, gas monitoring instruments

Chapter 4 - Project Boundary

4.1 Boundary principle

The project boundary shall include all emission sources and electricity flows necessary to quantify, in a complete and conservative manner, the net emission reductions attributable to the geothermal power project. The boundary shall be defined such that baseline and project scenarios are comparable and exclusions do not result in over-crediting.

The project proponent shall describe the boundary using a site layout, a process flow diagram, and a single-line electrical diagram that identify wells and fluid handling, separators, condensers, vents, abatement and reinjection systems (where applicable), auxiliary consumption, metering points, export/delivery points, and any backup generation.

4.2 Boundary components

The physical boundary shall include, at minimum, the geothermal production and reinjection system components relevant to electricity generation and emissions accounting, including production wells, gathering system, separators (where applicable), steam/brine handling, power block, condensers, cooling system, gas removal and handling systems, vent stacks, and reinjection wells and pipelines where reinjection is used.

The electrical boundary shall include generators, transformers, switchgear, and electrical infrastructure up to the point(s) of delivery used for quantification.

Auxiliary systems that consume electricity for operation of the geothermal facility shall be included for accounting purposes to the extent they affect net electricity delivered.

4.3 Greenhouse gases included

This methodology quantifies emission reductions through displaced electricity generation. Baseline emissions are primarily associated with CO₂ and may include CH₄ and N₂O where the baseline emission factor includes those gases.

Project emissions may include CO₂ and CH₄ released from geothermal fluids and gas handling systems, and CO₂, CH₄, and N₂O from fossil fuel combustion where fossil backup generation supplies the credited delivery configuration.

Hydrogen sulfide (H₂S) is not a greenhouse gas and is not included in GHG accounting under this methodology; however, where H₂S abatement systems affect gas handling or venting pathways relevant to CO₂/CH₄ emissions, the system configuration and performance shall be documented.

4.4 Boundary by delivery configuration

The boundary shall be defined according to delivery configuration.

4.4.1 Grid-connected export

For grid-connected projects, the electricity flow relevant for quantification is the net electricity exported to the grid at the defined point of interconnection or other defined delivery point. The boundary shall include all equipment and electricity flows up to the export meter used for quantification.

4.4.2 Captive/on-site displacement

For captive displacement projects, the electricity flow relevant for quantification is the net electricity delivered to the defined captive system. The boundary shall include delivery infrastructure to the point of delivery meter(s). The baseline boundary shall include the baseline electricity supply source(s) that would serve the captive system.

4.4.3 Mixed delivery

Where both grid export and captive supply occur, the project shall define separate delivery routes and metering arrangements such that electricity quantities attributable to each route are clearly determined and not double counted.

4.5 Geothermal gas pathway boundary

Where geothermal gas emissions are applicable, the boundary shall explicitly include the gas pathways from geothermal fluid production through to final disposition, including:

1. Gas separation points and gas handling equipment.

2. Any venting points to atmosphere.

3. Any gas abatement units, capture units, reinjection lines, or other gas management systems.

4. Any bypass lines, maintenance vents, or emergency release pathways that could result in emissions.

The project proponent shall document all normal and abnormal operating modes relevant to gas disposition and shall ensure that emissions accounting captures emissions in all relevant modes.

4.6 Treatment of auxiliary consumption and losses

Auxiliary consumption and electrical losses shall be treated consistently with the metering configuration and conservatively with respect to net electricity delivered.

Where net delivery is metered at the point of delivery and used for quantification, auxiliary consumption and internal losses are reflected in net delivery measurement. Where only gross generation is metered and net delivery is derived, auxiliary consumption and losses shall be quantified using measured data where feasible and conservatively estimated where necessary.

4.7 Backup generation and fossil electricity within the boundary

If fossil fuel-based generation is used within the project boundary to supply electricity to the same delivery configuration for which emission reductions are claimed, emissions from such generation shall be included as project emissions and deducted when calculating net emission reductions.

Where backup generation exists but is asserted not to contribute to the credited delivery, the project proponent shall demonstrate this through operational records and, where applicable, metering. If this cannot be demonstrated, the backup generation shall be included within the boundary and accounted conservatively.

4.8 Boundary exclusions

The following are excluded from the boundary under this methodology, unless explicitly required elsewhere in PCS:

1. Upstream lifecycle emissions from construction and manufacturing.

2. Indirect market effects and policy impacts not directly attributable to the project’s metered electricity delivery.

3. Emissions from unrelated activities not causally linked to the project’s electricity delivery and geothermal gas disposition pathways.

Exclusions shall be justified and shall not increase credited reductions.

4.9 Boundary table

Table 4-1. Boundary sources and inclusion status (geothermal power)

Source / sink / flow	Included in baseline scenario	Included in project scenario	Inclusion rationale
Net electricity delivered to grid at point of interconnection	Yes	Yes	Basis for displacement and crediting quantity.
Net electricity delivered to defined captive load(s)	Yes	Yes	Basis for displacement where captive configuration is used.
Baseline electricity generation supplying the same delivery configuration	Yes	No	Represents emissions that would occur without the project.
Geothermal electricity generation	No	Yes	Physical project activity producing electricity.
Auxiliary consumption and internal electrical losses	Reflected in net delivery or accounted for	Reflected in net delivery or accounted for	Prevents overstatement of net delivery.
CO₂ and CH₄ released from geothermal fluids via venting pathways	N/A	Yes (as project emissions)	Material project emissions must be included where applicable.
CO₂ and CH₄ managed via capture/reinjection/abatement (if any)	N/A	Yes (accounted through monitored disposition)	Claims require measurable evidence and accounting of residual emissions.
Fossil backup generation supplying credited delivery (if any)	No	Yes	Project emissions must be included where they affect credited electricity.
Upstream lifecycle emissions	No	No	Excluded under this methodology.
Indirect market/policy effects	No	No	Not attributable in a measurable, verifiable manner.

4.10 Documentation requirements

The project proponent shall provide boundary documentation sufficient for validation and verification, including:

1. Site map and equipment layout.

2. Process flow diagram showing geothermal fluid and gas handling pathways.

3. Single-line electrical diagram showing meters and delivery routes.

4. Identification of vent points and gas management systems, including bypass and emergency pathways.

5. Description of any backup generation and evidence of its operational role relative to credited delivery.

Failure to demonstrate an unambiguous and conservative boundary definition and auditable electricity and gas pathways shall render the project ineligible for issuance for the affected periods.

Chapter 5 - Baseline Scenario and Baseline Emissions

5.1 Baseline principle

The baseline scenario shall represent the plausible electricity generation that would occur in the absence of the geothermal project and shall be defined in a transparent, conservative, and verifiable manner. Baseline assumptions shall not be selected or structured to inflate emission reductions.

The baseline scenario shall be consistent with the delivery configuration(s) and boundary in Chapter 4.

5.2 Identification of the baseline scenario

The project proponent shall identify the baseline scenario using the procedure below.

1

Identify the electricity system and delivery route

The project shall identify the electricity system to which project electricity is delivered, distinguishing between grid-connected export, captive/on-site displacement, or mixed delivery. The electricity system definition shall be evidenced through interconnection documentation, wheeling agreements where applicable, and the metering configuration used for quantification.

2

Determine the most plausible baseline electricity supply

The baseline scenario shall be the most plausible source of electricity that would supply the same electricity service without the project activity.

• For grid-connected export, the baseline scenario shall be electricity supplied by the connected grid/system.

• For captive/on-site displacement, the baseline scenario shall be electricity supplied by the identified baseline source(s) that would serve the captive system, including existing or planned fossil generation and/or grid imports where those are credible alternatives.

• For mixed delivery, the baseline scenario shall be identified separately for each delivery route and shall be consistent with route-specific electricity system definitions.

The baseline scenario shall be justified using evidence. Where multiple plausible baseline scenarios exist, the project proponent shall select the scenario that is most realistic and shall apply conservative assumptions where uncertainty remains.

5.3 Baseline emission factor approach

Baseline emissions shall be calculated by applying an emission factor to net electricity delivered under each delivery route.

5.3.1 Grid-connected export: grid emission factor

For grid-connected delivery, baseline emissions shall be quantified using a grid emission factor applicable to the defined grid/system and the monitoring period. The project proponent shall demonstrate the source, derivation method, and applicability of the emission factor, including dataset version and temporal coverage.

The project shall not select an emission factor solely because it increases emission reductions. Where marginal displacement cannot be credibly established, the project proponent shall apply a conservative grid emission factor approach that does not overstate baseline emissions.

5.3.2 Captive/on-site displacement: baseline source emission factor

For captive displacement delivery, baseline emissions shall be calculated using an emission factor derived from the baseline electricity source(s). The emission factor shall be based on measured fuel consumption and electricity generation data where available. Where measured data are not available, the project proponent shall apply conservative defaults supported by credible sources and justified for the baseline technology and operating conditions.

If the baseline supply is grid electricity, the grid emission factor approach in Section 5.3.1 shall be applied.

5.3.3 Mixed delivery

For mixed delivery, baseline emissions shall be calculated separately for each route and summed, using the relevant emission factor approach for each route. The project shall prevent double counting of electricity quantities across routes.

5.4 Baseline emissions calculation

Baseline emissions for monitoring period shall be calculated as follows.

Table 5-1. Baseline emissions equations

Baseline type	Baseline emissions for monitoring period
Grid-connected export
Captive displacement
Mixed delivery

Where:

is baseline emissions in monitoring period (tCO₂e).

is net electricity delivered in monitoring period (MWh).

is grid emission factor applicable to monitoring period (tCO₂e/MWh).

is baseline captive source emission factor applicable to monitoring period (tCO₂e/MWh).

is net electricity delivered via route in monitoring period (MWh).

is baseline emission factor applicable to route in monitoring period (tCO₂e/MWh).

5.5 Baseline validity and updating

Baseline parameters and emission factors shall remain valid only where they continue to represent the defined electricity system and baseline supply. The project proponent shall update the baseline emission factor where required by PCS rules, where the underlying data source updates emission factors, or where material changes occur that affect baseline representativeness.

At minimum, baseline representativeness shall be assessed at each verification. If continued use of the existing emission factor would materially overstate baseline emissions, the project shall apply an updated factor for the relevant monitoring periods.

5.6 Documentation requirements

The project proponent shall document baseline scenario identification and emission factor selection with sufficient evidence for validation and verification, including electricity system definition, delivery configuration(s), emission factor sources (including versions), and justification of baseline scenario selection and assumptions.

Chapter 6 - Additionality

6.1 Requirement

The project activity shall be additional. The project proponent shall demonstrate that, in the absence of carbon credit revenues, the project would not have occurred as implemented, or would not have been implemented at the same scale and timing, and that the emission reductions are beyond those that would occur under the baseline scenario.

Additionality shall be assessed at validation. Where PCS requires reassessment at renewal or where material changes occur that affect the additionality basis, additionality shall be reassessed in accordance with PCS procedures.

6.2 Regulatory surplus test

The project shall not be eligible where the project activity or the achieved emission reductions are required by law, regulation, permit condition, legally binding renewable obligations, mandated utility procurement, or enforceable compliance targets applicable to the project proponent or the project facility.

The project proponent shall identify all applicable regulations and policy instruments relevant to geothermal development, drilling, reinjection, air emissions compliance, and electricity supply in the applicable jurisdiction and shall demonstrate that implementation of the project is not mandated.

Where reinjection or gas treatment is required by law or permit, emission reductions attributable to that legally required activity shall not be claimed as additional.

6.3 Investment analysis or barrier analysis

The project proponent shall demonstrate additionality using either an investment analysis or a barrier analysis. The selected approach shall be justified and supported by auditable evidence.

6.3.1 Investment analysis

Where investment analysis is applied, the project proponent shall demonstrate that the project is not financially attractive without carbon revenues, or that carbon revenues are decisive to meet an investment threshold required by decision-makers.

The analysis shall be based on project-specific data and reflect the information available at the time of the investment decision. Key assumptions (resource assessment, drilling success, plant performance, tariff/PPA terms, capex/opex, financing terms) shall be evidenced. Sensitivity analysis shall be conducted on material parameters and conservative assumptions shall be applied to avoid overstating the role of carbon revenue.

6.3.2 Barrier analysis

Where barrier analysis is applied, the project proponent shall demonstrate the presence of at least one credible barrier that would prevent implementation of the project in the absence of carbon revenues and that the project activity overcomes the identified barrier(s).

Barrier claims may include drilling/resource risk, limited access to finance, high cost of capital, technology constraints, grid interconnection constraints, institutional barriers, or other implementation obstacles. Claims shall be project-specific, evidenced, and causally linked to the implementation decision. Generic sector-wide claims without evidence shall not be accepted.

6.4 Common practice assessment

The project proponent shall assess whether the project activity is common practice in the applicable context. The applicable context shall be defined consistently, considering relevant geographic, market, and regulatory boundaries.

If the project activity is common practice, the project shall not be eligible unless the project proponent demonstrates that the project differs materially from common practice in a manner that affects its likelihood of implementation and that the difference is not driven by regulatory obligations.

6.5 Prior consideration and timing integrity

Where required by PCS rules, the project proponent shall demonstrate prior consideration of carbon finance through contemporaneous evidence. Absence of credible contemporaneous evidence, where required, shall render the project ineligible.

Where the project is implemented, operational, or financially closed prior to entering PCS, the project proponent shall demonstrate eligibility under PCS rules applicable to start date and prior consideration.

6.6 Geothermal emissions integrity condition

A project shall not be treated as additional on the basis of “renewable electricity” alone while ignoring material project emissions from geothermal gas releases.

Where geothermal gas emissions are relevant and material, additionality demonstration and crediting shall be based on net emission reductions as defined in Chapter 9 (baseline emissions minus project emissions and leakage). Projects with high geothermal CO₂ emissions intensity may yield low or zero net reductions; such projects may still be eligible in principle, but shall not claim reductions unless net reductions are demonstrated and verified.

6.7 Additionality failure conditions

A project shall be deemed not additional where any of the following apply:

1. The project is implemented to comply with a binding legal requirement or enforceable obligation.

2. The project is demonstrably financially attractive without carbon revenues and the project proponent cannot show carbon revenue is decisive.

3. Claimed barriers are not project-specific or are not supported by verifiable evidence.

4. The project activity is common practice and no credible differentiation is demonstrated.

5. Timing and prior consideration requirements applicable under PCS are not met.

6.8 Documentation requirements

The project proponent shall provide documentation sufficient for validation, including the regulatory surplus assessment, the selected additionality demonstration method (investment or barrier), common practice evidence and analysis, and any prior consideration evidence required by PCS rules. Documentation shall be traceable, dated where relevant, and auditable.

Chapter 7 - Project Emissions and/or Removals

7.1 Principle

Project emissions shall include all GHG emissions within the project boundary that are attributable to the project scenario and that are relevant to the quantification of net emission reductions under this methodology.

Geothermal power projects may have material project emissions due to release of non-condensable gases (including CO₂ and, where relevant, CH₄) from geothermal fluids and due to fossil fuel combustion where applicable. Where such emissions are relevant, they shall be quantified conservatively for each monitoring period.

This methodology does not quantify removals. No removals shall be claimed under PCS-TR-006.

7.2 Sources of project emissions

The project proponent shall assess the presence of the project emission sources below and shall include them where they occur.

7.2.1 CO₂ and CH₄ emissions from geothermal fluids

Where geothermal fluids contain non-condensable gases that are released to atmosphere through venting, cooling system gas removal, separator discharge, abatement bypass, maintenance vents, or other pathways, the resulting CO₂ and CH₄ emissions shall be included as project emissions.

Where gases are captured, treated, or reinjected, residual emissions and any emissions from bypass or venting during normal and abnormal operation shall be included.

7.2.2 Fossil backup or auxiliary generation supplying credited electricity

Where fossil fuel-based generation supplies electricity to the same delivery configuration for which emission reductions are claimed, emissions from such generation shall be included as project emissions.

7.2.3 Direct fossil fuel combustion within the project boundary

Where fossil fuels are combusted within the project boundary for purposes integral to electricity delivery and cannot be excluded without risk of over-crediting, emissions shall be accounted as project emissions.

7.3 Quantification of geothermal gas emissions

Geothermal gas emissions shall be quantified for each monitoring period using monitored data and a conservative approach suitable for validation and verification. The project proponent shall account for both the amount of geothermal fluid processed and the gas content of that fluid (or an equivalent direct measurement of gas flow), consistent with the plant configuration.

The project shall apply one of the following approaches, selected based on plant design and measurement feasibility. The selected approach shall be justified and applied consistently.

1. Direct gas flow measurement approach, where gas flow to vent/stack is measured and gas composition is analysed.

2. Fluid throughput and gas content approach, where geothermal fluid flow is measured and non-condensable gas content and composition are determined through representative sampling and analysis.

3. Other approach explicitly approved by PCS where (a) and (b) are not feasible, provided the approach is conservative and verifiable.

The project proponent shall define all emission points and ensure that the selected approach captures emissions under all relevant operating modes, including bypass and maintenance conditions.

Table 7-1. Geothermal gas emissions (generic equations)

Case	Project emissions component for monitoring period
Direct gas flow approach
Fluid throughput approach

Where:

PE_t^GAS is geothermal gas emissions in monitoring period (tCO₂e).

Q_GAS,k,t is quantity of gas vented/emitted at emission point in monitoring period (mass or volume, with defined conversion).

x_CO2,k,t , x_CH4,k,t are the fractions of CO₂ and CH₄ in the emitted gas (dimensionless).

F_FLUID,t is geothermal fluid throughput in monitoring period (mass or volume).is non-condensable gas content per unit geothermal fluid (mass or volume per unit fluid).

x_CO2,t , x_CH4,t are gas composition fractions for the non-condensable gas stream.

GWP_CO2 and GWP_CH4 are global warming potentials applied under PCS for the crediting context.

All units, conversions, and analytical methods shall be explicitly documented and consistently applied.

7.4 Quantification of fossil generation or combustion emissions

Where fossil generation or combustion is included, project emissions shall be quantified using measured fuel consumption and appropriate emission factors, or measured electricity generated by the fossil unit and a unit emission factor. The approach shall be justified and conservative.

Table 7-2. Fossil emissions equations (within boundary)

Case	Project emissions component for monitoring period
Fuel-based
Electricity-based

7.5 Total project emissions

Total project emissions for monitoring period shall be calculated as:

Where PE_t^OTHER includes any other included project emission sources (tCO₂e).

7.6 Excluded project emissions

Upstream lifecycle emissions from manufacturing, construction, and decommissioning are excluded from quantification under this methodology.

7.7 Documentation requirements

The project proponent shall document the assessment of project emission sources, the inclusion or exclusion rationale, the monitoring and calculation approach used, the data sources and analytical methods applied, and sufficient evidence to allow validation and verification.

For geothermal gas emissions, documentation shall include emission point identification, measurement instruments and calibration, sampling plans, laboratory methods, frequency of analysis, data processing steps, and treatment of abnormal operating modes and data gaps.

Chapter 8 - Leakage

8.1 Principle

Leakage is an increase in GHG emissions that occurs outside the project boundary and is attributable to the implementation of the project activity. Leakage shall be assessed and included in the net emission reduction calculation where it is measurable, attributable, and material.

Leakage shall not be used as a discretionary adjustment. Where leakage is included, the approach shall be transparent, conservative, and supported by evidence.

8.2 Leakage assessment for geothermal projects

Geothermal electricity generation projects generally displace electricity generation rather than shift emitting activities to another location. However, leakage may occur in captive displacement configurations or where baseline generators are relocated or operated elsewhere as a consequence of the project.

The project proponent shall assess leakage based on delivery configuration and project context. Where a leakage source is plausible, the project proponent shall document the assessment and provide evidence sufficient for validation and verification.

8.3 Potential leakage sources and treatment

8.3.1 Captive baseline generator relocation or increased operation

For captive displacement configurations, leakage may occur if the baseline fossil generator is relocated and operated elsewhere, or if its operation increases outside the project boundary as a consequence of the project activity. Where the project proponent has ownership, control, or contractual influence over the baseline generator, the project proponent shall assess generator disposition and subsequent operation.

Where such leakage is demonstrated and is material, leakage emissions shall be quantified conservatively using available operational data or conservative defaults.

8.3.2 System boundary manipulation

The electricity system definition established for baseline determination shall be maintained consistently. Changes to system definition shall not be used to increase baseline emissions. If electricity is delivered to a different system than defined, or system boundaries are redefined in a manner that increases credited reductions without justification, the project shall update the baseline approach and shall not claim increased reductions arising from such redefinition.

8.3.3 Prohibited treatment of non-attributable effects

The project shall not claim “negative leakage” or additional benefits through asserted improvements in grid operation, energy security, or co-benefits unless a PCS-approved methodology explicitly defines quantification and attribution rules for such effects. Claims that cannot be traced to monitored electricity delivery and the defined baseline shall not be used to adjust leakage.

8.4 Quantification of leakage

Leakage emissions shall be quantified only where attributable, measurable, and material. Where quantified, leakage emissions for monitoring period shall be calculated and deducted from emission reductions.

Table 8-1. Leakage accounting

Requirement element	Requirement
Identification	Leakage sources shall be identified based on project context and delivery configuration.
Materiality	Materiality shall be justified with evidence and conservative reasoning.
Quantification	Measured data shall be used where feasible; otherwise conservative defaults shall be justified.
Deduction	Quantified leakage emissions shall be deducted in the net emission reduction calculation.

Where leakage cannot be quantified due to lack of data, the project proponent shall apply a conservative approach that does not result in over-crediting, including application of conservative deductions where PCS permits such treatment.

8.5 Documentation requirements

The project proponent shall document leakage assessment, inclusion or exclusion rationale, data sources, assumptions, materiality justification, and any calculations performed. Evidence shall be sufficient to allow validation and verification of leakage conclusions.

Chapter 9 - Net GHG Impact and Crediting

9.1 Principle

Emission reductions credited under this methodology shall be calculated for each monitoring period as the net difference between baseline emissions and the sum of project emissions and leakage emissions. Crediting shall be based on monitored and verifiable data. No crediting shall be issued for reductions that are not supported by auditable records.

9.2 Net emission reductions

Net emission reductions for monitoring period shall be calculated as follows.

Table 9-1. Net emission reduction equation

Parameter	Equation
Net emission reductions	ERt=BEt - PEt - LEt

Where:

ER_t is emission reductions in monitoring period (tCO₂e).

BE_t is baseline emissions in monitoring period (tCO₂e), determined in Chapter 5.

PE_t is project emissions in monitoring period (tCO₂e), determined in Chapter 7 and including geothermal gas emissions where applicable.

LE_t is leakage emissions in monitoring period (tCO₂e), determined in Chapter 8.

Emission reductions shall not be claimed for periods in which ER_t ≤ 0 . Where ER_t is negative, it shall be reported and shall not be carried forward to offset positive emission reductions in other monitoring periods.

9.3 Creditable emission reductions and issuance

Creditable emission reductions shall equal verified emission reductions after application of any PCS-required adjustments, conservativeness provisions, or other deductions applicable to the project, including those arising from uncertainty treatment, monitoring non-conformities, or approved deviations.

Issuance shall occur only after successful verification and PCS review in accordance with PCS procedures. The project proponent shall ensure that all parameters and calculations used for the monitoring period are traceable to source records and can be independently reproduced.

9.4 Rounding and units

All electricity quantities shall be expressed in MWh. Emissions and emission reductions shall be expressed in tCO₂e.

Rounding shall be applied conservatively. Where rounding is required, values shall be rounded down to the nearest whole unit at the stage of credit issuance. Intermediate calculations shall retain sufficient decimal precision to avoid systematic inflation of results.

9.5 Crediting period and renewal

The crediting period length, renewal rules, and any limits on total crediting duration shall be applied in accordance with PCS requirements. The project proponent shall apply baseline update and additionality reassessment requirements applicable at renewal.

9.6 Aggregation and multiple delivery routes

Where the project has multiple delivery routes, emission reductions shall be calculated separately per route where different baseline emission factors apply, and then summed to derive total emission reductions for the monitoring period. Electricity quantities shall not be double counted between routes.

9.7 Documentation requirements

For each monitoring period, the project proponent shall provide a complete calculation record that includes baseline emissions, project emissions (including geothermal gas emissions where applicable), leakage emissions, net emission reductions, and any deductions or adjustments applied. Records shall be sufficient to support validation and verification.

Chapter 10 - Monitoring Requirements

10.1 Objective

The objective of monitoring under this methodology is to produce complete, accurate, and auditable data sufficient to quantify baseline emissions, project emissions (including geothermal gas emissions where applicable), leakage (where applicable), and net emission reductions for each monitoring period. Monitoring shall enable independent verification of reported results.

Monitoring shall be implemented as a system. The system shall include metering hardware, data collection and storage procedures, QA/QC controls, calibration and maintenance arrangements, and record retention practices.

10.2 Monitoring period

The project proponent shall define monitoring periods in accordance with PCS requirements. For each monitoring period, the project shall compile monitored data and supporting evidence that cover the full period without gaps. Where data gaps occur, the project proponent shall apply conservative gap-filling rules as set out in this chapter.

10.3 Parameters to be monitored

The project proponent shall monitor the parameters in Table 10-1, as applicable to the plant configuration and delivery configuration. Where a parameter is not applicable, the project proponent shall justify non-applicability and demonstrate that exclusion does not result in over-crediting.

Parameter	Description	Unit	Applicable to	Monitoring frequency	Data source / method	QA/QC requirements
(EG_{PJ,t})	Net electricity delivered for monitoring period (t) at defined delivery meter(s)	MWh	All projects	Continuous; aggregated per monitoring period	Revenue-grade or equivalent meter(s) at point(s) of delivery; settlement data where available	Meter calibration; tamper controls; audit trail
(EG_{PJ,t,r})	Net electricity delivered per delivery route (r)	MWh	Multi-route projects	Continuous; aggregated per period	Route-specific meters or auditable allocation	No double counting; reconciliation checks
Meter inventory and locations	Identification of each meter used and its location	N/A	All projects	At commissioning; update upon change	Meter register; single-line diagram	Change control; versioned diagrams
Calibration records	Calibration and accuracy verification evidence	N/A	All projects	Per applicable standard; at least annually unless stricter	Calibration certificates; maintenance logs	Traceability; corrective action records
Emission point register	Identification of all geothermal gas emission points (vents/stacks/bypass)	N/A	Projects with geothermal gas emissions	At commissioning; update upon change	Process flow diagram; plant O&M procedures	Change control; completeness check
(Q_{GAS,k,t}) or (F_{FLUID,t})	Gas flow at emission point(s) or fluid throughput	Mass/vol; or mass/vol fluid	Projects with geothermal gas emissions	Continuous where feasible; otherwise as justified	Gas flow meters; fluid flow meters; operational records	Calibration; plausibility checks; redundancy where available
(C_{NCG,t})	Non-condensable gas content per unit fluid	mass/vol per unit fluid	Fluid-throughput approach	Sampling-based; at frequency justified by variability	Sampling and lab analysis	Sampling QA/QC; chain-of-custody
(x_{CO2,t}, x_{CH4,t})	Gas composition fractions	dimensionless	Projects with geothermal gas emissions	At frequency justified by variability	Gas sampling and lab analysis	Laboratory QA/QC; method consistency
Abatement/reinjection performance records (if applicable)	Operating data demonstrating capture/treatment/reinjection performance	N/A	Projects claiming abatement/reinjection	Continuous/event-based; summarised per period	SCADA logs; maintenance records; performance tests	Evidence of bypass events; integrity checks
Fossil backup data (if applicable)	Electricity generated by backup unit(s) supplying credited delivery or fuel use	MWh / fuel units	Projects with fossil supply within boundary	Continuous when operating; aggregated per period	Generator meters; fuel logs; invoices	Fuel reconciliation; meter calibration
Baseline emission factor(s)	(EF_{GRID,t}), (EF_{CAPT,t})	tCO₂e/MWh	As applicable	At least per monitoring period	Official datasets / measured baseline source data	Version control; consistency checks

10.4 Electricity metering requirements

Net electricity delivered used for quantification shall be measured using revenue-grade or equivalent meters suitable for the installation context. Metering points shall be defined unambiguously and shall correspond to the delivery configuration used for baseline determination.

Where multiple meters exist (generator meters, station service meters, export meters), the project shall specify which meter(s) govern quantification. The selection shall prevent overstatement of net delivery and ensure that auxiliary consumption and losses are treated correctly.

10.5 Geothermal gas monitoring requirements

Where geothermal gas emissions are applicable, the project proponent shall implement monitoring sufficient to support conservative quantification of CO₂ and CH₄ emissions for each monitoring period.

The monitoring system shall include identification of all emission points, measurement of gas flow or fluid throughput as appropriate, and representative gas composition sampling and analysis. Monitoring shall capture normal operations and abnormal modes, including bypass, start-up/shutdown, maintenance venting, and emergency releases.

Where abatement or reinjection is used and claimed as reducing emissions, the project shall monitor and document abatement/reinjection operation and effectiveness. Performance claims shall not rely on assumed efficiency without auditable evidence.

10.6 Data quality and QA/QC

Monitoring data shall be subject to QA/QC controls sufficient to ensure accuracy and integrity. At minimum, the project shall implement:

1. Documented procedures for data collection, processing, review, and change control.

2. Calibration and maintenance controls for meters and monitoring instruments.

3. Sampling QA/QC and chain-of-custody procedures for gas sampling.

4. Internal consistency checks and plausibility checks, including reconciliation between electricity generation/export and plant operating parameters.

10.7 Data gaps and conservative treatment

Where monitored data are missing, corrupted, or otherwise unavailable, the project proponent shall apply a conservative approach to gap-filling that does not increase credited reductions.

For electricity, gap-filling shall use the best available evidence (redundant meters, settlement data). Where no reliable substitute exists, missing delivery data shall be treated as zero for the affected interval.

For geothermal gas monitoring parameters, where data gaps affect emissions quantification, the project proponent shall apply conservative substitution, including use of upper-bound gas content/composition values evidenced in the monitoring period, or other conservative methods suitable for verification. Where credible conservative quantification cannot be demonstrated, the project shall apply conservative deductions up to and including zero issuance for the affected period.

10.8 Record retention and accessibility

The project proponent shall retain monitoring records and supporting evidence for a period consistent with PCS requirements and sufficient to allow validation and verification across the crediting period and subsequent audits.

Records shall be stored to prevent loss and unauthorised modification and shall be made available to the VVB and PCS upon request.

10.9 Monitoring report content

For each monitoring period, the project proponent shall prepare a monitoring report that includes:

1

Monitoring period definition and operational summary

Provide definition of the monitoring period and a summary of operational conditions during the period.

2

Metering configuration and changes

Document metering configuration and any changes since the previous period.

3

Net electricity delivered data and evidence

Present net electricity delivered data and supporting evidence.

4

Geothermal gas monitoring results and calculations

Include geothermal gas monitoring results, datasets, QA/QC, and calculated emissions where applicable.

5

Baseline emission factor(s) applied and updates

Record baseline emission factors applied and any updates.

6

Fossil backup emissions (if applicable)

Provide fossil backup emissions data and calculations where applicable.

7

Leakage assessment and quantification (if applicable)

Include leakage assessment results and quantification.

8

Data gaps and conservative treatments; full net emission reductions calculation

Describe data gaps and conservative treatments applied and provide full calculation of net emission reductions.

Chapter 11 - Uncertainty and Conservativeness

11.1 Principle

Uncertainty shall be managed to protect environmental integrity. Where uncertainty affects the quantification of emission reductions, the project proponent shall apply conservative approaches that avoid over-crediting.

Uncertainty treatment shall be transparent, documented, and verifiable. Weak data shall not be compensated by favourable assumptions.

11.2 Sources of uncertainty

The project proponent shall identify material sources of uncertainty relevant to this methodology, including:

1. Measurement uncertainty in electricity metering and aggregation.

2. Uncertainty in baseline emission factors (grid or captive).

3. Uncertainty arising from data gaps, estimation, substitution, or monitoring system changes.

4. Uncertainty in allocation across delivery routes where mixed delivery occurs.

5. Uncertainty in geothermal gas emissions quantification, including variability in gas content and composition, sampling uncertainty, analytical uncertainty, and uncertainty in gas flow or fluid throughput measurement.

11.3 Electricity metering uncertainty

Meters used for quantification shall meet applicable accuracy requirements and shall be calibrated and maintained. Where meter accuracy is degraded, calibration is overdue, integrity cannot be demonstrated, or data are incomplete, the project proponent shall apply conservative treatment to the affected monitoring data.

Conservative treatment shall not result in higher net electricity delivered than would be supported by compliant metering and auditable records.

11.4 Baseline emission factor uncertainty

Baseline emission factors shall be applied consistently and updated when required. The project shall not select emission factor sources, temporal windows, or factor variants to increase emission reductions.

Where multiple credible emission factors exist, the project shall apply the factor that best represents the defined electricity system and does not increase credited reductions due to methodological choice. Where data quality is limited, conservative factors shall be applied.

11.5 Geothermal gas emissions uncertainty

Geothermal gas emissions may be material and variable. Where geothermal gas emissions are applicable, the project proponent shall design monitoring and quantification to ensure conservative estimation.

The following requirements apply:

1. Sampling and analysis frequency shall be justified based on expected variability. Low-frequency sampling is not acceptable where variability is high.

2. Measurement instruments for gas flow or fluid throughput shall be calibrated and suitable for the measured range.

3. Where gas composition varies materially, the project proponent shall apply conservative aggregation methods for the monitoring period.

4. Where abatement or reinjection is claimed, uncertainty in abatement effectiveness shall be treated conservatively. Bypass events shall be treated as emissions unless demonstrated otherwise with evidence.

5. Where uncertainty remains high, conservative deductions shall be applied to emission reductions for the affected monitoring period.

Uncertainty shall not be used as a basis to omit geothermal gas emissions or to apply favourable assumptions.

11.6 Data gaps and estimation

Data gaps increase uncertainty. Gap-filling shall follow the conservative rules in Chapter 10.

Where geothermal gas data gaps occur, the project shall apply conservative substitution, including use of upper-bound emission factors or gas content values supported by monitored evidence, and shall document the basis. Where credible conservative quantification cannot be demonstrated, the project shall apply conservative deductions up to and including zero issuance for the affected period.

Any estimation method that materially increases emission reductions shall require explicit justification and may be rejected at verification.

11.7 Conservative adjustments and deductions

Where uncertainty cannot be adequately reduced through improved monitoring or credible data sources, the project proponent shall apply conservative deductions to emission reductions for the affected monitoring period.

Deductions may be applied to electricity delivered, baseline emission factor, geothermal gas emissions estimates, or final emission reductions, provided the approach is transparent and results in under-crediting rather than over-crediting.

11.8 Documentation requirements

The project proponent shall maintain documentation sufficient for validation and verification, including:

1. Identification of material uncertainty sources.

2. Meter specifications and calibration records.

3. Baseline emission factor sources and update records.

4. Geothermal gas monitoring design, QA/QC procedures, datasets, analytical methods, and uncertainty treatment.

5. Records of data gaps, estimation methods, and conservative deductions applied.

Chapter 12 - Validation and Verification Guidance

12.1 Objective

This chapter defines the minimum validation and verification checks that shall be applied by the Validation and Verification Body (VVB) to determine whether the project is eligible, correctly applies this methodology, and has quantified emission reductions in a complete and conservative manner.

Where the VVB identifies non-conformities that materially affect applicability, geothermal gas emissions accounting, baseline integrity, additionality, monitoring integrity, or quantification results, the VVB shall not issue a positive opinion for registration or issuance unless the non-conformities are corrected and corrective evidence is provided.

12.2 Validation scope (ex ante)

At validation, the VVB shall confirm that the project meets eligibility and applicability conditions and that the project design and monitoring system can implement this methodology as written.

12.2.1 Applicability and eligibility checks

The VVB shall confirm that the project type is within scope and that any exclusion triggers do not apply, including the requirement for auditable electricity metering and the geothermal gas emissions eligibility condition.

The VVB shall assess whether the project boundary is clearly defined and supported by engineering documentation, including process flow diagrams that identify all geothermal gas emission points, abatement/reinjection systems, and bypass/emergency pathways.

The VVB shall verify legal compliance and permitting, including geothermal resource rights, drilling approvals, environmental and air emissions approvals, reinjection approvals where applicable, and grid interconnection.

The VVB shall assess whether the project proponent has the right to claim emission reductions and whether double counting risks are addressed.

12.2.2 Baseline scenario and emission factor checks

The VVB shall assess whether the baseline scenario is plausible, conservative, and consistent with the delivery configuration. The VVB shall confirm that the electricity system definition is clear, evidenced, and consistently applied.

The VVB shall verify that the baseline emission factor approach selected is applicable to the defined grid/system or baseline source and is not selected to maximise emission reductions. The VVB shall confirm baseline update triggers and the project’s capability to apply updates during monitoring.

12.2.3 Additionality checks

The VVB shall assess the additionality demonstration for completeness and credibility. The VVB shall confirm that the project is not legally mandated and that the investment or barrier analysis is based on project-specific evidence, reflects decision-time context, and applies conservative assumptions.

The VVB shall assess common practice and determine whether the conclusion is supported by sufficient data and an appropriate definition of the applicable context.

12.2.4 Geothermal gas emissions validation checks

The VVB shall assess whether geothermal gas emissions are relevant and potentially material and whether the project proponent has correctly identified all emission points.

The VVB shall verify the monitoring approach selected for geothermal gas emissions, including the appropriateness of gas flow or fluid throughput measurement, sampling design, laboratory methods, calibration, QA/QC, chain-of-custody, and procedures for abnormal operating modes.

Where the project claims abatement, capture, or reinjection effects, the VVB shall assess whether performance monitoring can demonstrate effectiveness and whether bypass events will be captured and accounted.

If geothermal gas emissions are expected to be material and the project proponent cannot demonstrate conservative and verifiable quantification and monitoring capability, the VVB shall determine that the project is not eligible under this methodology.

12.2.5 Monitoring system and data integrity checks

The VVB shall assess whether the monitoring plan and system are adequate to measure net electricity delivered, apply baseline emission factors, and quantify project emissions and leakage where applicable.

The VVB shall confirm metering points are unambiguous, calibration and QA/QC procedures are defined, and the data management system provides an auditable trail from raw records to reported totals.

12.3 Verification scope (ex post)

At verification, the VVB shall confirm that monitoring data and calculations for each monitoring period are complete, accurate, and traceable, and that the project remains eligible under this methodology.

12.3.1 Electricity delivery verification

The VVB shall verify net electricity delivered using primary meter records and settlement data where applicable. The VVB shall reconcile reported totals against raw data and assess data gaps and conservative treatments.

12.3.2 Baseline emission factor verification

The VVB shall confirm the baseline emission factor applied corresponds to the defined electricity system and monitoring period and that any required updates have been applied. The VVB shall assess whether emission factor selection is consistent and not designed to increase credited reductions.

12.3.3 Geothermal gas emissions verification

The VVB shall verify geothermal gas emissions calculations for the monitoring period, including raw monitoring datasets, sampling and laboratory results, QA/QC records, calibration records, evidence of all emission points, and treatment of bypass and abnormal operation.

Where monitoring was not performed as specified, where emission points are missing, or where data integrity is inadequate, the VVB shall treat this as a material non-conformity and require correction or conservative treatment up to and including zero issuance for the affected period where integrity cannot be established.

12.3.4 Fossil emissions and leakage verification

Where fossil backup generation or other project emission sources are included, the VVB shall verify fuel and/or generation data, emission factors used, and calculations. Where leakage is quantified, the VVB shall verify attribution, materiality, and calculation.

12.3.5 Calculation verification

The VVB shall reproduce emission reduction calculations using verified inputs and shall confirm correct equations, units, and deductions. The VVB shall confirm that emission reductions are not claimed for periods with zero or negative results and that rounding is conservative.

12.4 Non-conformities and corrective actions

The VVB shall classify non-conformities based on materiality. Material non-conformities shall be corrected before a positive validation opinion or verification statement is issued.

Where corrections require changes to gas monitoring procedures, emission point registers, baseline application, or calculation methods, the VVB shall verify revised materials and confirm that revisions do not introduce over-crediting.

12.5 Common failure conditions under this methodology

The following conditions shall be treated as material unless the project proponent demonstrates otherwise:

1. Unclear electricity system definition or delivery configuration.

2. Use of an emission factor not applicable to the defined system or monitoring period.

3. Metering configuration that cannot demonstrate net electricity delivered.

4. Incomplete emission point register or missing vent/bypass pathways.

5. Gas sampling frequency or QA/QC insufficient for variability and annualisation.

6. Claims of abatement/reinjection without auditable performance evidence.

7. Data gaps treated in a non-conservative manner.

8. Double counting risk due to unclear ownership or overlapping claims.

9. Failure to disclose material changes affecting gas pathways or monitoring.

12.6 Documentation requirements

The project proponent shall provide the VVB and PCS with all documents and datasets necessary to perform the checks in this chapter. Evidence shall be organised, traceable, and sufficient to support replication of results and independent assessment.

Chapter 13 - References

13.1 General requirement

The project proponent shall use credible, publicly available, and verifiable sources for all default values, emission factors, and technical assumptions applied under this methodology. References shall be sufficiently specific to allow independent replication, including the title, issuing entity, version number (or publication date), and relevant sections or datasets.

Where multiple credible sources exist for a parameter, the project proponent shall justify the selection and shall apply conservative choices where uncertainty exists.

13.2 Minimum reference categories

The following reference categories shall be used where applicable:

1. PCS documents, including the relevant PCS standards, this methodology, any referenced PCS methodological tools, and the applicable PCS templates and forms.

2. Host country laws and regulations relevant to geothermal development, drilling, reinjection, environmental and air emissions compliance, and electricity supply.

3. Official grid emission factor publications or officially recognised electricity system emissions datasets applicable to the defined grid/system.

4. National or international fuel emission factors and combustion guidelines where fossil backup generation is included.

5. Technical standards for electricity metering, calibration, and accuracy requirements applicable in the host jurisdiction or electricity market context.

6. Scientific and technical references used to support geothermal gas measurement, sampling, and quantification approaches where geothermal gas emissions are applicable.

13.3 Citation and recordkeeping requirements

All sources used shall be cited in the project documentation and retained as part of the project record. Where a data source is updated periodically, the project proponent shall retain the specific version used for each monitoring period and demonstrate consistency with baseline update requirements.

Annex A - Parameters and Default Values

A.1 General

This annex specifies the minimum parameters required to implement this methodology. Project proponents shall use measured data where required. Default values may be used only where explicitly allowed and shall be justified as applicable and conservative.

Parameter	Description	Unit	Applicable to	Data source / method	Monitoring frequency	Default value allowed
(EG_{PJ,t})	Net electricity delivered for monitoring period (t) at defined delivery meter(s)	MWh	All projects	Revenue-grade/equivalent meter(s); settlement data where available	Continuous; aggregated per period	No
(EG_{PJ,t,r})	Net electricity delivered via route (r) in period (t)	MWh	Multi-route projects	Route meters or auditable allocation	Continuous; aggregated per period	No
(EF_{GRID,t})	Grid emission factor for defined grid/system	tCO₂e/MWh	Grid-connected	Official grid EF dataset applicable to grid/system and period	At least per period; updated as required	Yes, only where PCS recognises the source as default
(EF_{CAPT,t})	Baseline captive source emission factor	tCO₂e/MWh	Captive displacement	Derived from measured baseline data or conservative defaults	At least per period	Limited; only if measured data unavailable and conservative defaults justified
(Q_{GAS,k,t})	Gas quantity emitted at emission point (k)	mass/vol	Direct gas flow approach	Gas flow measurement and records	Continuous where feasible; otherwise justified	No
(F_{FLUID,t})	Geothermal fluid throughput	mass/vol	Fluid-throughput approach	Flow measurement and operational records	Continuous; aggregated per period	No
(C_{NCG,t})	Non-condensable gas content per unit fluid	mass/vol per unit	Fluid-throughput approach	Sampling and lab analysis	As justified by variability	Limited; conservative only
(x_{CO2,t}), (x_{CH4,t})	Gas composition fractions	dimensionless	Gas emissions accounting	Sampling and lab analysis	As justified by variability	Limited; conservative only
(PE_{t})	Total project emissions	tCO₂e	All projects (if applicable)	Calculated per Chapter 7	Per period	No
(LE_{t})	Leakage emissions	tCO₂e	Projects with identified leakage	Calculated per Chapter 8	Per period	No
(FC_{i,t})	Fuel consumption of fuel (i) for included fossil generation/combustion	fuel unit	Fossil PE	Fuel logs, invoices, meters	Continuous/event-based; aggregated	No
(EF_{FUEL,i})	Emission factor for fuel (i)	tCO₂e/fuel unit	Fossil PE	Official factors or authoritative references	When factor updates or annually	Yes, if authoritative published factors are used
Meter calibration status	Calibration and accuracy evidence	N/A	All projects	Certificates and maintenance logs	At least annually (or per standard)	No

Annex B - Worked Example

B.1 Example purpose and limitations

This worked example is illustrative. Project proponents shall use project-specific monitored data and applicable emission factors and shall include geothermal gas emissions where applicable.

B.2 Example inputs (grid-connected geothermal plant with vented CO₂)

Assume a geothermal plant exporting to the grid.

Table B-1. Example inputs for monitoring period

Item	Value	Notes
Net electricity exported EGPJ,t	180,000 MWh	From export meter
Grid emission factor EFGRID,t	0.600 tCO₂e/MWh	Example only
Geothermal gas emissions PEtGAS	35,000 tCO₂e	Quantified from monitored gas/fluid and composition
Fossil project emissions PEtFOSSIL	0 tCO₂e	None in this example
Leakage emissions LEt	0 tCO₂e	None identified

B.3 Baseline emissions

B.4 Net emission reductions

No credits are issued for any period in which the result is zero or negative.

Annex C - Monitoring Data Sheet

C.1 Monitoring log requirements

The project proponent shall maintain a monitoring log that allows independent reproduction of monitoring period totals and linkage to raw records. The monitoring log shall be maintained for each monitoring period and retained with supporting evidence.

Table C-1. Monitoring data sheet (minimum fields)

Field	Description	Unit / format	Required
Monitoring period ID	Unique identifier	Text	Yes
Period start date/time	Start of monitoring period	YYYY-MM-DD hh:mm	Yes
Period end date/time	End of monitoring period	YYYY-MM-DD hh:mm	Yes
Project configuration	New / Expansion / Retrofit / Abatement	Text	Yes
Delivery configuration	Grid / Captive / Mixed	Text	Yes
Meter ID (primary)	Export/delivery meter identifier	Text	Yes
Meter location	Point of delivery/interconnection	Text	Yes
Meter type and class	Revenue-grade/equivalent; accuracy class	Text	Yes
Calibration due date	Next calibration deadline	YYYY-MM-DD	Yes
Calibration certificate ref.	Reference number/link	Text	Yes
Net electricity delivered	Period total net delivered	MWh	Yes
Route identifier	If mixed delivery, route label	Text	Conditional
Net electricity delivered per route	Route total	MWh	Conditional
Emission point register version	Register ref. (vents/bypass)	Text	Conditional
Gas flow / fluid throughput data ref.	Dataset reference	Text	Conditional
Sampling and lab report refs	Composition/NCG results	Text	Conditional
Abatement/reinjection operating records ref.	Performance dataset reference	Text	Conditional
Calculated PE^GAS_t	Geothermal gas emissions	tCO₂e	Conditional
Fossil backup used for credited delivery	Yes/No	Text	Yes
Fuel type and quantity	Fuel and consumption	Unit as metered	Conditional
Fuel EF source/version	Dataset name, version/date	Text	Conditional
Calculated PE^FOSSIL_t	Fossil emissions	tCO₂e	Conditional
Leakage identified	Yes/No	Text	Yes
Leakage description and ref.	Description and evidence	Text	Conditional
Calculated LE_t	Leakage emissions	tCO₂e	Conditional
Baseline EF used	or	tCO₂e/MWh	Conditional
Baseline EF source/version	Dataset name, version/date	Text	Conditional
Calculated BE_t	Baseline emissions	tCO₂e	Yes
Calculated PE_t	Total project emissions	tCO₂e	Yes
Calculated ER_t	Net emission reductions	tCO₂e	Yes
Data gaps present	Yes/No	Text	Yes
Gap treatment description	Method and conservative treatment	Text	Conditional
Prepared by / date	Responsible person and date	Text / YYYY-MM-DD	Yes
Internal review by / date	Reviewer and date	Text / YYYY-MM-DD	Yes

Definitions and Acronyms

D.1 Definitions

For the purposes of this methodology, the following definitions apply.

Abatement system means equipment and procedures installed and operated to reduce atmospheric releases of gases associated with geothermal operations, including systems that capture, treat, reinject, mineralize, or otherwise manage non-condensable gases.

Additionality means the demonstration that the project activity results in emission reductions that would not have occurred in the absence of the project and the incentive from carbon crediting.

Auxiliary electricity consumption means electricity consumed to operate the geothermal facility and associated systems, including pumps, fans, cooling system loads, controls, lighting, communications, substation auxiliaries, and other operational loads.

Baseline emissions (BE_t) means the GHG emissions that would occur in monitoring period t in the absence of the project activity, associated with the generation of the electricity displaced by the project.

Baseline emission factor means the emission intensity applied to the displaced electricity generation in the baseline scenario, expressed in tCO₂e per MWh.

Baseline scenario means the most plausible electricity supply that would serve the same electricity service in the absence of the project activity, determined in accordance with Chapter 5.

Bypass means an operational condition in which geothermal gases or geothermal fluids are diverted around normal gas handling, capture, abatement, or reinjection systems, including during start-up, shutdown, maintenance, upset conditions, or emergencies.

Captive electricity system means a defined electricity supply and consumption arrangement in which electricity is delivered to and used by a specific facility or set of loads, and where displacement is assessed against an identified baseline electricity source (e.g., on-site fossil generation or grid import).

Commissioning date means the date on which the geothermal plant, or a defined project phase, is first capable of commercial operation and delivery of electricity as evidenced by commissioning certificates and/or grid operator acceptance.

Delivery configuration means the physical and contractual arrangement by which project electricity is delivered, including grid export, captive supply, or mixed delivery, as defined and evidenced for quantification under this methodology.

Electricity system means the grid or defined captive supply system to which the project delivers electricity and against which displacement is assessed.

Emission point means any identified location within the project boundary at which geothermal gases may be released to atmosphere, including vent stacks, gas removal system outlets, separator vents, condenser gas outlets, abatement bypass vents, maintenance vents, and emergency release points.

Emission point register means the controlled record that lists and describes all emission points, including their locations, operating modes, and the monitoring approach used to quantify emissions from each point.

Emission reductions (ER_t) means the net GHG emission reductions in monitoring period t, calculated as baseline emissions minus project emissions and leakage emissions, in accordance with Chapter 9.

Fluid throughput (F_FLUID,t) means the quantity of geothermal fluid processed by the geothermal facility in monitoring period t, expressed in mass or volume units consistent with the monitoring approach.

Geothermal fluid means the liquid and/or steam produced from a geothermal reservoir and used for electricity generation.

Geothermal gas emissions (PE^GAS_t) means project emissions attributable to CO₂ and CH₄ released from geothermal fluids through identified emission points in monitoring period t, expressed in tCO₂e.

Grid emission factor (EF_GRID,t) means the emission intensity of electricity generation for the defined grid/system applicable to monitoring period t, expressed in tCO₂e per MWh, and applied to quantify baseline emissions for grid-connected delivery.

Leakage (LE_t) means an increase in GHG emissions occurring outside the project boundary that is attributable to the project activity and is measurable, attributable, and material under this methodology.

Material change means a change in project design, wellfield operation, fluid handling, gas handling pathways, abatement or reinjection configuration, delivery configuration, ownership/control, metering configuration, boundary definition, or operational conditions that may affect applicability, baseline, additionality, monitoring, or quantification under this methodology.

Metering point means a physical location where electricity is measured by a defined meter used for quantification, including generation meters, station service meters, and delivery/export meters.

Monitoring period means the time interval for which monitored data are aggregated and emission reductions are quantified and verified for issuance purposes.

Net electricity delivered (EG_PJ,t) means the net quantity of electricity measured as delivered through the defined delivery meter(s) for monitoring period t, expressed in MWh, and used as the basis for baseline emissions calculations under this methodology.

Non-condensable gases (NCG) means gases contained in geothermal fluids that do not condense under plant operating conditions and may be separated and discharged through gas handling systems, including CO₂ and, where relevant, CH₄.

Non-condensable gas content (C_NCG,t) means the quantity of non-condensable gases per unit geothermal fluid, determined for monitoring period t using representative sampling and analysis, expressed in mass or volume per unit fluid.

Point of delivery means the agreed location at which electricity delivery is measured for quantification purposes under this methodology (e.g., point of interconnection export meter, or captive delivery meter), as defined in the monitoring system.

Project boundary means the physical and operational boundary that includes relevant components and emission sources necessary to quantify emission reductions in a complete and conservative manner under this methodology.

Project emissions (PE_t) means GHG emissions occurring within the project boundary in monitoring period t that are attributable to the project scenario and relevant to the quantification of net emission reductions, including geothermal gas emissions and any fossil backup generation supplying the credited delivery configuration where applicable.

Reinjection means the return of geothermal fluids and/or separated gases to the geothermal reservoir through reinjection wells, whether for reservoir management, environmental control, or emissions management.

Revenue-grade meter means an electricity meter suitable for commercial settlement or equivalent accuracy and integrity requirements in the applicable electricity market or jurisdiction.

Route (r) means a defined electricity delivery pathway used for accounting where multiple delivery configurations exist, each supported by metering or auditable allocation.

Sampling plan means a documented plan that specifies sampling locations, frequency, methods, preservation, chain-of-custody, and laboratory analytical methods used to determine non-condensable gas content and composition.

Validation and verification means independent assessment activities performed to confirm eligibility, methodological correctness, data integrity, and quantified emission reductions for registration and issuance under PCS.

D.2 Acronyms

Table D-1. Acronyms

Acronym	Meaning
BE	Baseline Emissions
EF	Emission Factor
EG	Net Electricity Delivered / Exported (as used in equations)
ER	Emission Reductions
GHG	Greenhouse Gas
LE	Leakage Emissions
MWh	Megawatt-hour
NCG	Non-Condensable Gases
PE	Project Emissions
PCS	Planetary Carbon Standard
PCC	Planetary Carbon Credit
QA/QC	Quality Assurance / Quality Control
SCADA	Supervisory Control and Data Acquisition
VVB	Validation and Verification Body