PCS TR 005 Hydro Power Methdology_v1.0

Document Control

Document identification

• Document code: PCS-MT-005

• Title: Hydropower 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 hydropower 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Superseded versions

No superseded versions for v1.0.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 Superseded versions shall be archived and retained for traceability and audit purposes.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 hydropower electricity generation under the Planetary Carbon Standard (PCS). It defines applicability conditions, baseline determination requirements, monitoring requirements, and calculation boundaries for hydropower projects.

1.2 Intended use

This methodology shall be applied to hydropower 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 shall be 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 hydropower and demonstrate measurable displacement of electricity generation that would otherwise occur in the absence of the project. The scope is limited to emission reductions from electricity generation and delivery.

Hydropower projects can introduce project emissions that are material, including emissions associated with reservoirs. Accordingly, applicability under this methodology is conditional on the project type and the ability to monitor and account for relevant emissions in a conservative and verifiable manner.

2.2 Eligible project types

A project is eligible under this methodology where the project activity consists of installation and operation of hydropower equipment and associated infrastructure that generates electricity and delivers electricity to an eligible electricity system.

The following project types are eligible, subject to the conditions in this chapter.

2.2.1 Run-of-river hydropower

Run-of-river projects are eligible where the project does not create a new reservoir or materially expand an existing reservoir, and where impoundment is limited such that it does not introduce material reservoir emissions attributable to the project activity.

2.2.2 Existing reservoir hydropower (facility addition or efficiency improvement)

Projects that add power generation capability to an existing dam or reservoir, or improve efficiency/output of an existing hydropower facility, are eligible where the project does not cause a material increase in reservoir area or material change in reservoir operation that would materially increase reservoir emissions attributable to the project.

2.2.3 New reservoir hydropower

New reservoir hydropower is eligible only where the project proponent can quantify and monitor reservoir-related project emissions in a manner that is conservative and verifiable for the crediting period and can demonstrate that the net emission reductions remain positive after accounting for project emissions and leakage.

If reservoir emissions cannot be quantified with sufficient evidence, the methodology shall be deemed not applicable.

2.3 Applicable delivery configurations

This methodology recognises distinct delivery configurations. Applicability depends on the configuration and the project’s ability to meet evidence and monitoring requirements.

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 clearly identified; applicable baseline emission factor approach shall be justified and consistently applied.
Captive/on-site displacement (fossil generation)	Applicable	Baseline supply shall be identified and evidenced; displacement shall be demonstrated through metered delivery and operating records; project emissions including relevant reservoir emissions shall be accounted for where applicable.
Mixed grid export and captive supply	Applicable	Electricity quantities shall be separately accounted for each route; double counting shall be prevented; route-specific baseline emission factor(s) shall be applied consistently.
Hydropower used primarily for fuel production (e.g., hydrogen/e-fuels)	Not applicable	Not eligible unless PCS issues a dedicated methodology for the pathway.
Integrated hybrid dispatch systems (hydro + solar + fossil with inseparable attribution)	Not applicable	Use the applicable hybrid methodology where attribution rules are explicit.

2.4 Exclusions and non-applicable cases

This methodology shall not be applied to:

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

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

• Projects where the hydropower facility is primarily designed for non-power purposes and electricity generation is incidental, unless the project can demonstrate additionality and separable quantification of the electricity service attributable to the project activity.

• Projects involving pumped storage where the net electricity delivered and net emissions impacts cannot be conservatively quantified under this methodology.

• Projects where material reservoir emissions are expected but cannot be conservatively quantified and monitored.

2.5 Applicability conditions

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

2.5.1 Demonstrable displacement

The project shall demonstrate that electricity generated and delivered displaces electricity generation that would otherwise occur. Displacement shall be quantified using the baseline approach in Chapter 5.

2.5.2 Boundary consistency

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

2.5.3 Reservoir emissions applicability screening

The project proponent shall assess whether reservoir-related emissions are relevant and material for the project type. Where reservoir emissions are relevant, the project shall include them as project emissions and shall apply the monitoring and quantification requirements specified in this methodology.

Where the project does not create a new reservoir and does not materially change reservoir area or operation, the project proponent shall justify exclusion of reservoir emissions with evidence sufficient for validation and verification.

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, including reservoir emissions where applicable.

If monitoring feasibility cannot be demonstrated at validation, the methodology shall be deemed not applicable.

2.6 Geographic applicability

This methodology is globally applicable, subject to the availability of credible data required to implement baseline determination and monitoring, including electricity system identification, emission factor sourcing or derivation, and the ability to measure and account for material project emissions.

2.7 Data and monitoring feasibility requirement

At minimum, the project shall be capable of producing auditable records for:

1. Net electricity delivered by configuration and metering point;

2. Facility operational records relevant to quantification;

3. Data required to apply baseline emission factor approach;

4. Where applicable, data required to quantify reservoir-related emissions in a conservative manner.

If these data cannot be produced with defensible QA/QC, the project shall not proceed to registration 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 hydropower generation equipment and associated infrastructure that generates electricity from flowing water and delivers electricity to an eligible electricity system as defined in Chapter 2.

The project shall clearly identify whether it is run-of-river, an addition to an existing reservoir/dam, an efficiency upgrade, or a new reservoir hydropower project. Where the project includes multiple components or phases, the project proponent shall demonstrate separability of the credited activity and shall prevent double counting across components or phases.

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 construction, water use, environmental clearance, land access, dam safety approvals where applicable, grid interconnection, and operation 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 for compliance, offsetting, or voluntary claims under another program or instrument unless an explicit and verifiable non-overlap arrangement exists and is consistent with PCS requirements on double counting.

Where the project involves power purchase agreements, wheeling, concessions, joint ventures, or public-private ownership, the project proponent shall document attribute ownership and confirm that the mitigation outcome is not claimed by another entity.

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 the additionality provisions of this methodology. The project shall not be eligible where the project activity is legally mandated or otherwise non-additional under PCS rules.

3.8 Reservoir emissions eligibility requirement

Reservoir-related emissions shall be addressed as an eligibility condition.

1. Where the project creates a new reservoir, materially expands the reservoir area, or materially changes reservoir operation in a way that can reasonably be expected to affect reservoir emissions, the project proponent shall quantify reservoir-related emissions as project emissions and shall implement the monitoring requirements specified in this methodology.

2. The project shall not be eligible if reservoir-related emissions are expected to be material and the project proponent cannot demonstrate a conservative and verifiable quantification and monitoring approach for the crediting period.

3. Where the project does not create or materially expand a reservoir and does not materially change reservoir operation, the project proponent may exclude reservoir emissions only where it provides evidence sufficient for validation and verification that the exclusion is justified and conservative.

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, where applicable, reservoir-related emissions parameters and 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, water management regime relevant to reservoir emissions, delivery configuration, ownership, metering arrangement, or operational control that may affect applicability, baseline, additionality, monitoring, or quantification under this methodology.

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:

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

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

• Reservoir emissions are relevant and potentially material but are not quantified and monitored conservatively and verifiably.

• Pumped storage or operational regimes materially affect net electricity and net emissions, and the project cannot demonstrate conservative accounting.

• 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 type	Technical description, layout, single-line diagram, equipment list, commissioning records
Water rights and permits	Water use approvals, environmental clearance, land access, dam safety approvals where applicable
Grid interconnection / delivery	Interconnection agreements, export meters, wheeling documents where applicable
Right to claim / non-overlap	Contracts (PPA/concession/JV), attribute ownership clauses, declarations preventing double counting
Start date / prior consideration (if required)	Investment decision documents, board approvals, 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
Reservoir emissions applicability	Reservoir design/operation description, inundation area evidence, operating regime, monitoring plan for reservoir emissions (where applicable)
Monitoring feasibility	Meter specs, calibration plan/records, data management procedures, reservoir monitoring instruments (where applicable)

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 hydropower 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 project boundary using a site layout and a single-line electrical diagram that identify the generating units, waterways and hydraulic structures relevant to generation, auxiliary consumption, metering points, export/delivery points, and any backup generation. Where a reservoir is relevant for this methodology, the boundary description shall also include the reservoir area and the operational regime relevant to reservoir emissions.

4.2 Boundary components

The physical boundary shall include, at minimum, the hydropower generating units and all associated infrastructure required for electricity generation and delivery, including intake structures, penstocks or canals, turbines, generators, power house equipment, transformers, switchgear, and the electrical infrastructure up to the point(s) of delivery used for quantification.

Auxiliary systems that consume electricity for project operation, including station service loads, controls, lighting, communications, and substation auxiliaries, shall be included for accounting purposes to the extent they affect net electricity delivered.

Where the project creates a reservoir, expands a reservoir, or operates in a manner that materially affects reservoir conditions, the reservoir shall be included within the project boundary for the purpose of quantifying reservoir-related emissions as project emissions.

4.3 Greenhouse gases included

This methodology quantifies emission reductions through displaced electricity generation. Carbon dioxide (CO₂) associated with baseline electricity generation is included. Methane (CH₄) and nitrous oxide (N₂O) associated with baseline electricity generation shall be included where the baseline emission factor applied includes these gases.

Project emissions under hydropower may include CO₂ and CH₄ emissions attributable to reservoir-related processes where a reservoir is within scope and applicable. Where fossil fuel combustion occurs within the project boundary and supplies the credited delivery configuration, emissions from such combustion shall be included as project emissions.

Upstream lifecycle emissions (manufacture, construction, decommissioning) are excluded under this methodology unless PCS explicitly adopts lifecycle accounting requirements for this activity type.

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 generation source(s) that would supply the same 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 Reservoir boundary requirements

Where reservoir emissions are applicable under this methodology, the project shall define the reservoir boundary for emissions accounting. The reservoir boundary shall include the inundated area attributable to the project activity and any relevant components necessary to characterise reservoir emissions in a conservative manner.

Where the project involves an existing reservoir, the project proponent shall distinguish between pre-project reservoir conditions and project-induced changes relevant to reservoir emissions. Claims shall not attribute pre-existing reservoir emissions reductions to the project.

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, auxiliary consumption and internal losses are inherently reflected in the 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 hydropower delivery configuration used for quantification.

Exclusions shall be justified and shall not increase credited reductions.

4.9 Boundary table

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

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 (grid mix or fossil captive generator)	Yes	No	Represents emissions that would occur without the project.
Hydropower electricity generation	No	Yes	Physical project activity producing electricity.
Auxiliary consumption of hydropower facility	Reflected in net delivery or accounted for	Reflected in net delivery or accounted for	Ensures net delivery is not overstated.
Transformer and internal line losses up to delivery meter	Reflected in delivery measurement or deducted	Reflected in delivery measurement or deducted	Prevents overstatement of net delivery.
Fossil backup generation supplying credited delivery (if any)	No	Yes	Project emissions must be included where they affect credited electricity.
Reservoir-related emissions (where applicable)	As defined by baseline scenario	Yes (as project emissions)	Required where the reservoir is created/expanded or operation changes and emissions may be material.
Upstream lifecycle emissions (manufacture/construction)	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:

• Site map and equipment layout identifying all relevant boundary components.

• Single-line electrical diagram identifying generation meters, auxiliary loads, export/delivery meters, and delivery routes.

• Description of delivery configuration(s) and points of delivery used for quantification.

• Description of reservoir characteristics and operating regime where reservoir emissions are applicable.

• 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 flows 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 hydropower 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. Baseline and project scenarios shall be comparable. Where project emissions are material under this methodology, the baseline approach shall not ignore those emissions in a way that results in over-crediting.

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, including planning context, existing supply arrangements, contracts, and technical feasibility. 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. The project proponent shall apply one of the emission factor approaches below, based on delivery configuration and data availability.

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 emission factor approach shall be applied consistently. 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 delivery 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 Water management and baseline integrity

The baseline scenario shall not assume changes in water availability, dispatch priority, or operating regime that materially increase credited reductions unless such assumptions are evidenced and conservative. Claims based on hypothetical “must-run” status, avoided spillage, or avoided curtailment of other generators shall not be used to inflate baseline emissions.

5.7 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 and delivery configuration(s).

• Grid identification and interconnection evidence, or captive supply definition and evidence.

• Data sources used for emission factors, including version and applicability.

• Justification of baseline scenario selection and conservative assumptions.

• Any baseline update applied and the basis for the update.

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 hydropower development, water use, dam safety, environmental compliance, and electricity supply in the applicable jurisdiction and shall demonstrate that implementation of the project is not mandated.

Where the project is undertaken to meet a binding obligation associated with a concession, public service requirement, or legally binding water infrastructure program, the project proponent shall demonstrate that the credited hydropower component is not required and is not business-as-usual under that obligation.

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 hydropower 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 the investment decision was taken. Key assumptions, including capital costs, hydrology assumptions, tariff or PPA terms, operating costs, and financing conditions, shall be transparent and supported by evidence. Sensitivity analysis shall be conducted on material parameters, and conservative assumptions shall be applied to avoid overstating the role of carbon revenue.

Where power revenues are guaranteed through tariff regimes or long-term contracts, the analysis shall reflect those contractual terms. Where merchant power revenues are assumed, assumptions shall be conservative and supported by credible evidence.

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).

Barriers may include constraints such as limited access to finance, high cost of capital, significant hydrological variability risk, technology constraints, grid interconnection constraints, institutional barriers, or other implementation obstacles that are material for the project. Barrier claims shall be project-specific, evidenced, and causally linked to the implementation decision. Generic sector-wide barriers 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 differentiation is not driven by regulatory obligations.

6.5 Multi-purpose infrastructure and incidental power generation

Where the hydropower facility is part of a multi-purpose dam or water infrastructure project primarily designed for objectives such as irrigation, flood control, navigation, or water supply, the project proponent shall demonstrate that the hydropower component is not incidental and is additional.

A project shall not be eligible where the hydropower component would be implemented as part of the infrastructure project regardless of carbon revenues and where carbon revenues do not materially affect the decision to install, operate, or expand the hydropower generating capacity.

Where a dam exists and the project adds generation capacity, the project proponent shall demonstrate that the addition is not mandated and is not business-as-usual under the concession or operating arrangement.

6.6 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.

6.7 Additionality failure conditions

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

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

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

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

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

• The hydropower component is incidental to a multi-purpose infrastructure project and would occur regardless of carbon revenues.

• 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, any assessment relating to multi-purpose infrastructure, 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.

Hydropower projects may have material project emissions, including reservoir-related emissions. Where reservoir emissions are applicable under this methodology, they shall be treated as project emissions and shall be quantified conservatively for each monitoring period.

This methodology does not quantify removals. No removals shall be claimed under PCS-TR-005.

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 Reservoir-related emissions (where applicable)

Where the project creates a new reservoir, expands reservoir area, or materially changes reservoir operation in a manner that can reasonably be expected to affect reservoir emissions, reservoir-related emissions shall be included as project emissions.

Reservoir-related emissions shall include emissions attributable to processes occurring in the reservoir system that are relevant and material for the purposes of this methodology. Where methane emissions are expected to be relevant, methane shall be included in the accounting.

The project proponent shall define the reservoir emissions accounting boundary consistently with Chapter 4 and shall apply the monitoring and quantification requirements specified in this methodology.

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 under this methodology, emissions from such generation shall be included as project emissions and deducted from baseline emissions when calculating net emission reductions.

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. Fossil fuel use that is demonstrably unrelated to electricity delivery may be excluded only where the project proponent provides sufficient evidence and exclusion does not increase credited reductions.

7.3 Treatment of auxiliary electricity consumption

Auxiliary electricity consumption is not treated as a separate emission source where net electricity delivered is directly metered at the point of delivery and used for quantification, because auxiliary consumption and internal losses are reflected in net delivery. Where only gross generation is metered and net delivery is derived, auxiliary consumption shall be accounted for to prevent overstatement of net delivery.

7.4 Quantification of project emissions

Project emissions for each monitoring period shall be calculated as the sum of emissions from included sources.

7.4.1 Quantification of fossil generation emissions

Where fossil generation is included, project emissions shall be quantified using a fuel-based approach based on measured fuel consumption and appropriate emission factors, or an electricity-based approach using measured electricity generated by the fossil unit and a unit emission factor. The selected approach shall be justified and conservatively applied.

Table 7-1. Project emission equations (fossil generation within boundary)

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

Where:

• FC_i,t is fuel consumption of fuel i during period t.

• EF_FUEL,i is emission factor for fuel i.

• EG_FOSSIL,j,t is electricity generated by fossil unit j during period t.

• EF_UNIT,j is emission factor for fossil unit j.

7.4.2 Quantification of reservoir emissions (where applicable)

Reservoir emissions shall be quantified for each monitoring period using a method that is conservative, transparent, and verifiable. The method shall be capable of being validated and verified using monitored data and documented assumptions.

Reservoir emissions quantification shall, at minimum, address the reservoir area relevant to the project activity and the operating regime during the monitoring period. Where direct measurement is applied, measurement design, sampling frequency, and QA/QC shall be sufficient to support conservative annualisation for the monitoring period. Where models or default factors are applied, the project proponent shall justify applicability and shall apply conservative assumptions.

Reservoir emissions quantification shall not be omitted where reservoir emissions are expected to be material. Where uncertainty is high, conservative deductions shall be applied to protect against over-crediting.

For the purposes of net emission reduction calculation, reservoir emissions shall be included in project emissions as:

Where:

• PE_t is total project emissions for monitoring period (tCO₂e).

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

• PE_t^RES is reservoir-related emissions for monitoring period (tCO₂e).

7.5 Excluded project emissions

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

Emissions associated with personnel travel and other indirect activities are excluded unless PCS establishes explicit requirements to include such sources for this activity type.

7.6 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 emission factors applied, and sufficient evidence to allow validation and verification.

Where reservoir emissions are applicable, documentation shall include reservoir characteristics, inundation area evidence, operating regime description, monitoring design, QA/QC procedures, and the basis for annualisation and uncertainty treatment.

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 hydropower projects

Hydropower projects may cause leakage where the project activity results in displacement or redistribution of emitting activities outside the boundary, including changes in baseline generation patterns, relocation of baseline generators in captive systems, or increased emissions in connected systems that are attributable to project operation.

The project proponent shall assess leakage for the applicable delivery configuration and project context. Where potential leakage sources exist, 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 Activity shifting attributable to reservoir creation or operation

Where reservoir creation or operation results in demonstrable displacement of activities that increase emissions outside the project boundary and are attributable to the project, such leakage shall be assessed. Generic claims of displacement without evidence shall not be accepted.

8.3.4 Prohibited treatment of non-attributable effects

The project shall not claim “negative leakage” or additional benefits through asserted improvements in grid operation, water management, flood control, or other co-benefits unless a PCS-approved methodology explicitly defines the 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

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 reservoir 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 reservoir 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 reservoir 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 project type 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
Operating regime summary	Key operational characteristics relevant to delivery configuration	N/A	All projects	Per monitoring period	Dispatch records; operating logs	Consistency with reported electricity
Curtailment (if applicable)	Evidence of curtailment periods and reasons	N/A	Projects experiencing curtailment	Event-based; summarised per period	Grid operator notices; SCADA flags	Cross-check vs export data
Fossil backup generation 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	Reconciliation of fuel purchase/stock; meter calibration
(EF_{GRID,t}) / (EF_{CAPT,t})	Baseline emission factor(s) applied	tCO₂e/MWh	As applicable	At least per monitoring period	Official datasets / measured baseline source data	Version control; consistency checks
Reservoir area and operating conditions (if applicable)	Reservoir characteristics relevant to emissions accounting	N/A	Reservoir-applicable projects	At least annually; update upon material change	Reservoir management records; maps; level/area data	Traceability; change control
Reservoir emissions monitoring data (if applicable)	Data required to quantify reservoir emissions	As applicable	Reservoir-applicable projects	As required by the adopted quantification approach	Measurements and/or model inputs supported by evidence	Sampling QA/QC; conservative treatment; documented uncertainty

10.4 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 Reservoir monitoring requirements (where applicable)

Where reservoir emissions are applicable, the project proponent shall implement monitoring sufficient to support conservative quantification of reservoir-related emissions for each monitoring period.

The monitoring system shall include, as applicable: reservoir boundary definition, inundation area evidence, operating regime records, and the measurement or input data required by the quantification approach adopted. The project proponent shall ensure that monitoring is designed to capture variability relevant to emissions estimation and that QA/QC procedures are applied to protect data integrity.

Where monitoring cannot meet these requirements, the project shall apply conservative deductions or shall be deemed ineligible for issuance for the affected periods.

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 documented procedures for data collection, processing, review, and change control, including an auditable trail from raw records to reported totals.

Internal consistency checks shall be applied, including reconciliation of electricity quantities across meters where available and plausibility checks against expected operational performance.

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.

Gap-filling shall be based on the best available evidence, such as redundant meters, SCADA records validated against compliant meters, or settlement statements. Where no reliable substitute exists, missing electricity delivery data shall be treated as zero for the affected interval, or another conservative method shall be applied consistent with PCS procedures.

All data gaps and treatments shall be documented with the period affected and the impact on results.

10.8 Record retention and accessibility

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

Records shall be stored in a manner that prevents loss and unauthorised modification and shall be made available to the VVB and PCS for review upon request.

10.9 Monitoring report content

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

1. Monitoring period definition and operational summary.

2. Metering configuration and any changes since the previous period.

3. Net electricity delivered data and evidence.

4. Baseline emission factor(s) applied and any updates.

5. Project emissions, including reservoir emissions where applicable, and supporting evidence.

6. Leakage assessment and quantification where applicable.

7. Data gaps and conservative treatments applied.

8. 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:

• Measurement uncertainty in electricity metering and aggregation.

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

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

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

• For reservoir-applicable projects, uncertainty in reservoir emissions quantification, including sampling uncertainty, spatial/temporal variability, model structure uncertainty, and parameter uncertainty.

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 Reservoir emissions uncertainty (where applicable)

Reservoir emissions may be material and uncertain. Where reservoir emissions are applicable, the project proponent shall design monitoring and quantification to ensure conservative estimation.

The following requirements apply.

• Monitoring design shall address relevant variability. Sampling and measurement frequency shall be sufficient to support conservative annualisation for the monitoring period.

• Where models are used, parameter selection shall be justified and conservative.

• Where uncertainty remains high, conservative deductions shall be applied to reservoir emissions estimates in a manner that avoids over-crediting.

• Failure to implement credible reservoir emissions monitoring, where required, shall trigger conservative treatment up to and including ineligibility for issuance for the affected period.

Uncertainty shall not be treated as a basis to omit reservoir 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 estimation is unavoidable, estimates shall be based on the most direct evidence available and shall be selected such that they do not increase credited emission reductions relative to plausible alternatives.

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, emission factors, reservoir emission 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:

• Identification of material uncertainty sources.

• Meter specifications and calibration records.

• Baseline emission factor sources and update records.

• For reservoir-applicable projects, reservoir monitoring design, QA/QC procedures, datasets, model specifications where relevant, and uncertainty treatment.

• 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, reservoir 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 pumped storage non-applicability where relevant and reservoir emissions eligibility requirements where applicable.

The VVB shall assess whether the project boundary is clearly defined and supported by engineering documentation and whether reservoir boundary definition is complete where reservoir emissions are applicable.

The VVB shall verify legal compliance and permitting, including water rights and environmental clearances, and 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.

Where the project is part of multi-purpose water infrastructure, the VVB shall assess whether the hydropower component is incidental and whether additionality is credibly demonstrated for the power component rather than for the broader infrastructure.

12.2.4 Reservoir emissions validation checks (where applicable)

Where reservoir emissions are applicable, the VVB shall assess whether the project proponent has identified reservoir applicability correctly and whether the reservoir emissions quantification approach is conservative and verifiable.

The VVB shall verify the reservoir boundary definition, reservoir area evidence, and operating regime description. The VVB shall assess whether monitoring design, measurement methods and/or model inputs, QA/QC, and uncertainty treatment are sufficient to support conservative estimation for each monitoring period.

If reservoir 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 that metering points are unambiguous, that calibration and QA/QC procedures are defined, and that 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 for the monitoring period using primary meter records and settlement data where applicable. The VVB shall reconcile reported totals against raw data and shall assess whether data gaps occurred and whether gap-filling was applied conservatively.

The VVB shall review calibration records and assess whether metering accuracy and integrity were maintained. Where calibration was overdue or metering integrity is uncertain, the VVB shall require conservative treatment and assess the impact on results.

12.3.2 Baseline emission factor verification

The VVB shall confirm that 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 the project proponent has applied emission factors consistently and has not selected sources or periods to increase credited reductions.

12.3.3 Reservoir emissions verification (where applicable)

Where reservoir emissions are applicable, the VVB shall verify the reservoir emissions calculations for the monitoring period, including the underlying monitoring data, QA/QC records, assumptions, model parameters where relevant, and uncertainty treatment.

The VVB shall assess whether reservoir monitoring was conducted as specified, whether data gaps occurred, and whether any conservative deductions were applied where uncertainty was material.

If reservoir emissions are not quantified or are quantified using unsupported assumptions, the VVB shall treat this as a material non-conformity and shall require correction or conservative treatment up to and including zero issuance for the affected period where integrity cannot be established.

12.3.4 Project 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 the 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 net reductions and that rounding is applied conservatively.

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 monitoring procedures, reservoir emissions accounting, 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. Inadequate reservoir emissions applicability assessment where reservoir emissions are relevant.

5. Reservoir emissions monitoring that is insufficient, inconsistent, or unverifiable.

6. Unsubstantiated baseline assumptions or boundary definitions.

7. Additionality evidence that is not contemporaneous or not project-specific.

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

9. Failure to disclose material changes affecting reservoir operation, applicability, baseline, 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 hydropower development, water use, dam safety, environmental 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 reservoir emissions quantification approaches where reservoir 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 (such as grid emission factor datasets), the project proponent shall retain the specific version used for each monitoring period and shall 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 the defined delivery meter(s)	MWh	All projects	Revenue-grade or equivalent meter(s) at point(s) of delivery; settlement data where available	Continuous; aggregated per monitoring period	No
(EG_{PJ,t,r})	Net electricity delivered via route (r) in period (t)	MWh	Multi-route projects	Route-specific meters or auditable allocation based on metered flows	Continuous; aggregated per period	No
(EF_{GRID,t})	Grid emission factor for the defined grid/system applicable to period (t)	tCO₂e/MWh	Grid-connected	Official grid EF publication or authoritative dataset applicable to the grid/system and period	At least per monitoring period; updated when source updates	Yes, only where PCS recognises the source as default
(EF_{CAPT,t})	Baseline captive source emission factor applicable to period (t)	tCO₂e/MWh	Captive displacement	Derived from measured fuel and generation data where available; otherwise conservative defaults justified	At least per monitoring period	Limited; only if measured data unavailable and conservative defaults are justified
(PE_{t})	Project emissions for period (t)	tCO₂e	All projects (if applicable)	Calculated per Chapter 7	Per monitoring period	No
(PE^{RES}_{t})	Reservoir-related emissions for period (t)	tCO₂e	Reservoir-applicable projects	Quantified using monitored data and conservative approach per Chapter 7	Per monitoring period	Limited; only if explicitly permitted and conservative
(LE_{t})	Leakage emissions for period (t)	tCO₂e	Projects with identified leakage	Calculated per Chapter 8	Per monitoring period	No
(FC_{i,t})	Fuel consumption of fuel (i) during period (t) for included fossil generation	fuel unit	Projects with fossil generation in boundary	Fuel logs, invoices, tank records, flow meters	Continuous/event-based; aggregated per period	No
(EF_{FUEL,i})	Emission factor for fuel (i)	tCO₂e/fuel unit	Projects with fuel-based fossil PE	Official factors or authoritative references	When factor updates or annually	Yes, if authoritative published factors are used
(EG_{FOSSIL,j,t})	Electricity generated by fossil unit (j) supplying credited delivery route in period (t)	MWh	Projects using electricity-based fossil PE	Unit meter(s), settlement records	Continuous; aggregated per period	No
(EF_{UNIT,j})	Emission factor for fossil unit (j)	tCO₂e/MWh	Projects using electricity-based fossil PE	Unit-specific factor supported by evidence; conservative where uncertain	When factor updates or at verification	Limited; only with conservative justification
Meter calibration status	Confirmation primary meters are calibrated and within tolerance	N/A	All projects	Calibration 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 and demonstrates calculation logic and reporting format. Project proponents shall use project-specific monitored data, applicable emission factors, and include project emissions such as reservoir emissions where applicable.

B.2 Example inputs (grid-connected run-of-river project)

Assume a run-of-river hydropower plant exporting electricity to the grid with no reservoir emissions applicable and no fossil backup supplying credited export.

Table B-1. Example inputs for monitoring period

Item	Value	Notes
Net electricity exported EG_PJ,t	250,000 MWh	From delivery meter totals
Grid emission factor EF_GRID,t	0.550 tCO₂e/MWh	Example only; must be sourced and applicable
Fossil project emissions PE^FOSSIL_t	0 tCO₂e	None in this example
Reservoir emissions PE^RES_ts	0 tCO₂e	Not applicable in this example
Leakage emissions LE_t	0 tCO₂e	None identified

B.3 Baseline emissions

B.4 Net emission reductions

Net emission reductions = Baseline emissions − Project emissions − Leakage = 137,500 − 0 − 0 = 137,500 tCO₂e

B.5 Example including reservoir emissions (illustrative)

Assume the same electricity export and emission factor, but reservoir emissions are applicable and quantified as PE^RES_t tCO₂e for the period, with no other project emissions and no leakage.

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 type	Run-of-river / Existing reservoir / New reservoir	Text	Yes
Delivery configuration	Grid / Captive / Mixed	Text	Yes
Meter ID (primary)	Unique meter identifier used for quantification	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 electricity	MWh	Yes
Route identifier	If mixed delivery, route label	Text	Conditional
Net electricity delivered per route	Route total	MWh	Conditional
Curtailment occurrence	Yes/No	Text	Yes
Curtailment evidence ref.	Grid notice/SCADA ref.	Text	Conditional
Baseline EF used	or	tCO₂e/MWh	Conditional
Baseline EF source/version	Dataset name, version/date	Text	Conditional
Fossil backup used for credited delivery	Yes/No	Text	Yes
Backup generator ID	Identifier	Text	Conditional
Backup electricity generated	Electricity supplied to credited route	MWh	Conditional
Fuel type and quantity	Fuel and consumption	Unit as metered	Conditional
Fuel EF source	Publication/dataset and version	Text	Conditional
Reservoir emissions applicable	Yes/No	Text	Yes
Reservoir boundary reference	Map/version reference	Text	Conditional
Reservoir operating regime summary	Key operating conditions	Text	Conditional
Reservoir emissions data reference	Dataset/sampling record reference	Text	Conditional
Calculated PEtRES	Reservoir 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
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.

• 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 hydropower facility and associated systems, including station service 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.

• 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 hydropower 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.

• Curtailment means a reduction in electricity output or export below what could have been generated, due to grid constraints, dispatch instructions, system security requirements, or other external limitations, evidenced by operational and/or grid operator records.

• 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 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.

• 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, delivery configuration, ownership/control, metering configuration, boundary definition, reservoir operation relevant to emissions, 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.

• 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 reservoir emissions where applicable and fossil backup generation supplying the credited delivery configuration where applicable.

• Pumped storage means an electricity storage configuration in which electricity is used to pump water to an upper reservoir and electricity is later generated by releasing the stored water through turbines.

• Reservoir means an impounded water body formed by a dam or similar structure that stores water for hydropower generation and/or other purposes.

• Reservoir emissions (PE^RES_t) means GHG emissions attributable to the reservoir system included within the project boundary for monitoring period t, quantified as project emissions where applicable under this methodology.

• Repowering means replacement or refurbishment of hydropower equipment or major components of an existing hydropower facility to extend operating life and/or increase electricity generation, without necessarily changing the dam/reservoir structure.

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

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

• Run-of-river means a hydropower configuration where electricity generation is primarily based on river flow with no new reservoir, or only minimal impoundment that does not materially create reservoir emissions attributable to the project activity.

• 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	Electricity Delivered / Exported (as used in equations)
ER	Emission Reductions
GHG	Greenhouse Gas
LE	Leakage Emissions
MWh	Megawatt-hour
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