PCS TR 010 Fuel Switch Methodology_v1.0
Document Control
Document identification
Document code: PCS-TR-010
Title: Fuel Switch Methodology
Scope: Defines eligibility conditions, boundary and baseline determination rules, additionality requirements, monitoring requirements, leakage treatment, and calculation procedures for PCS projects that reduce GHG emissions by switching fuels used to deliver the same useful energy or industrial service, including switches in stationary combustion equipment and process heat applications, with controls to prevent over-crediting due to activity reduction, service change, or baseline manipulation.
Version history and change log
Table DC-1. Revision history
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Superseded versions
No superseded versions for v1.0.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 Superseded versions shall be archived and retained for traceability and audit purposes.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 activity-specific requirements for quantifying emission reductions from projects that reduce emissions by switching from a higher-emitting fuel to a lower-emitting fuel while delivering the same useful energy or industrial service under the Planetary Carbon Standard (PCS). It defines conditions for eligibility, baseline determination requirements, monitoring requirements, and conservative calculation rules for fuel switching projects.
1.2 Intended use
This methodology shall be applied to projects that implement fuel switching in stationary combustion equipment or industrial systems, where the service output remains equivalent and where emissions can be quantified credibly using monitored fuel consumption, fuel properties, and conservative baseline approaches.
The project proponent shall quantify emission reductions using monitored and verifiable data. Where fuel properties or consumption cannot be measured directly, conservative approaches may be applied only where allowed under this methodology and where environmental integrity is protected through conservative assumptions and verification controls.
1.3 Relationship to other PCS documents
This methodology shall be applied together with applicable PCS standards, any PCS methodological tools referenced by this methodology, and the approved PCS templates and forms used for project submission and monitoring/reporting. In the event of inconsistency, 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. PCS templates and forms required for submissions 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 do not apply until they enter into force under PCS governance procedures.
Chapter 2 - Scope and Applicability
2.1 Scope
This methodology applies to projects that reduce GHG emissions by switching fuels used in stationary combustion equipment or industrial energy systems while providing the same useful energy output or industrial service. The methodology covers fuel switches that reduce combustion-related CO₂e emissions, including where switches affect CO₂, CH₄, and N₂O emissions through different fuel characteristics and combustion conditions.
The methodology is designed for situations where baseline fuel use is identifiable, project fuel use is measurable, and service equivalence can be demonstrated and monitored.
2.2 Eligible project types
Eligible project types include fuel switching in boilers, furnaces, kilns, heaters, dryers, engines, and other stationary equipment used for process heat, steam generation, or mechanical energy supply, provided that the project can demonstrate comparable service delivery and can quantify baseline and project emissions conservatively.
Projects may involve switching from coal to natural gas, heavy fuel oil to natural gas, diesel to LNG, biomass to biogas, or other combinations where the project fuel is lower-emitting for the same useful output. Switching from one fossil fuel to another is eligible only where net reductions are demonstrated after accounting for all relevant emissions and leakage.
This methodology may be applied to switching to electricity only where PCS provides explicit treatment for electricity-based fuel switching within this methodology or where an applicable PCS electricity methodology is used. Electricity-based switches require careful baseline alignment and shall not be claimed under this methodology without explicit applicability.
2.3 Exclusions and non-applicable cases
This methodology shall not be applied where the claimed reductions are primarily due to reduced activity, reduced service output, or production curtailment rather than fuel switching. It shall not be applied where baseline fuel use cannot be credibly established using representative and auditable data, or where monitoring cannot produce auditable evidence of fuel consumption and relevant service output.
Fuel switching that is legally mandated, required by enforceable permit conditions, or required by a binding policy obligation is not eligible.
Fuel switching projects that include significant upstream emissions changes that are likely to reverse reductions, and that cannot be addressed through leakage treatment, shall not be eligible under this methodology.
2.4 Applicability conditions
A project shall be applicable under this methodology only where it can define the useful energy output or industrial service delivered, can establish a credible baseline fuel and baseline fuel consumption for that service, can monitor project fuel consumption and service output in a verifiable manner, and can demonstrate service equivalence such that reductions are not driven by reduced output.
The project shall identify the fuel types, combustion equipment, boundary definition, monitoring points, and emission factor sources required to quantify emissions for each monitoring period.
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 a defined fuel switch in identified stationary combustion equipment or industrial energy systems, resulting in lower GHG emissions per unit of useful energy output or industrial service delivered relative to the baseline scenario.
The project shall identify the baseline fuel, the project fuel, the combustion equipment affected, and the operating configuration. The project shall define whether the switch is a full conversion, partial substitution, co-firing arrangement, or a phased transition. Where partial substitution occurs, the project shall quantify emissions using monitored fuel quantities for each fuel used and shall not assume full switching unless demonstrated by evidence.
Where multiple equipment units are included, the project shall define the boundary for each unit or define a facility boundary that remains auditable and conservative and prevents shifting of baseline fuel use outside the boundary.
3.3 Service equivalence and output integrity
The project shall demonstrate that the useful energy output or industrial service delivered is equivalent between baseline and project scenarios. The service metric shall be defined and shall be measurable using auditable records. Acceptable service metrics include steam output, heat delivered, production throughput supported by the heat system, or other appropriate metrics that allow like-for-like comparison.
The project shall not claim emission reductions that arise primarily from reduced service delivery, reduced production, or curtailed activity. Where output varies, the project shall apply normalization to the defined service metric such that baseline and project emissions are compared on an equivalent service basis.
If service equivalence cannot be demonstrated credibly and conservatively, the project shall not be eligible under this methodology.
3.4 Baseline eligibility and representativeness
The project shall establish a credible baseline scenario consistent with this methodology. Baseline fuel use shall be identifiable and supported by representative and auditable data.
Where baseline fuel consumption is derived from historical data, the project shall demonstrate that the baseline period is representative of normal operations and that data are complete and auditable. Where the baseline period includes abnormal events that would bias the baseline upward, the project shall justify any exclusions and demonstrate that the resulting baseline remains conservative.
Baseline shall not be defined as a hypothetical worst-case fuel mix or inefficient operation unless PCS explicitly allows such a baseline and the project demonstrates conservativeness.
3.5 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 fuel switching, equipment modification, safety, and operation have been obtained and are valid at the time of registration.
Where the switch involves changes in emissions control systems, gas supply infrastructure, storage tanks, burners, safety systems, or other regulated elements, the project proponent shall demonstrate compliance with relevant environmental and safety requirements.
3.6 Regulatory surplus and policy interaction
The project shall not be eligible where the fuel switch is legally mandated, required by enforceable permit conditions, required by binding sectoral obligations, or required by an enforceable fuel standard.
Where policies exist that encourage or subsidize fuel switching without mandating it, the project proponent shall disclose such policies and incentives and demonstrate that the project remains additional and that credited reductions are not double counted or otherwise claimed under those instruments.
3.7 Right to claim emission reductions and avoidance of double counting
The project proponent shall demonstrate legal authority and contractual rights to claim 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 fuel supply contracts, utility programs, government incentives, or emissions reporting obligations exist, the project proponent shall disclose participation and demonstrate that claims do not overlap.
3.8 Start date and prior consideration
The project shall define a clear project start date. The project proponent shall identify commissioning or changeover dates that demonstrate when the project fuel began supplying the defined service.
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.
3.9 Monitoring system eligibility
Eligibility under this methodology is conditional on auditable monitoring. The project shall have a monitoring system capable of producing complete and auditable records for all parameters required to quantify emission reductions for each monitoring period.
Monitoring shall include fuel quantity measurement for each fuel used, fuel properties where required, and measurement of the defined service output or service driver needed for normalization. Where continuous measurement is not feasible, the project shall justify the monitoring approach and demonstrate that it remains conservative and verifiable.
If monitoring is not feasible at validation for the parameters required by this methodology, the project shall not be eligible for registration under this methodology.
3.10 Material change controls
The project proponent shall disclose any material change that may affect applicability, baseline, additionality, monitoring, or quantification. Material changes include changes in equipment capacity, operating schedule, fuel quality, fuel supply arrangements, control logic, combustion tuning, emissions control systems, service output definition, boundary definition, or metering configuration.
Where a material change occurs, the project proponent shall follow 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. Baseline fuel use cannot be credibly established using representative and auditable data. Service equivalence cannot be demonstrated or monitored. The project relies on reduced output rather than fuel switching. Fuel switching is legally mandated. Double counting risk exists due to unclear ownership or overlapping claims. Monitoring cannot produce auditable fuel and service data.
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)
Fuel switch description
Technical description, process narrative, PFD/P&ID where relevant, burner and equipment specs
Baseline fuel and baseline data
Baseline fuel purchase records, invoices, meter logs, fuel stock records, baseline period justification
Project fuel and implementation
Project fuel supply contracts, commissioning records, changeover records, safety checks
Service equivalence
Defined service metric, monitoring approach, production/steam/heat records, normalization rationale
Permits and compliance
Permits and approvals, compliance documentation, safety and environmental clearances
Additionality / regulatory surplus
Regulatory analysis, incentive disclosures, decision documentation
Monitoring feasibility
Meter register, calibration plan/records, fuel sampling plan where required, QA/QC procedures
Right to claim / non-overlap
Contracts, declarations, attribute ownership clauses, non-overlap statements
Material change controls
Change control procedures, records of changes, PCS approvals where applicable
Chapter 4 - Project Boundary
4.1 Boundary principle
The project boundary shall include all emission sources and energy flows necessary to quantify, in a complete and conservative manner, the net emission reductions attributable to the fuel switch while delivering the same useful energy output or industrial service. The boundary shall be defined such that baseline and project scenarios are comparable and exclusions do not result in over-crediting.
The boundary shall be defined around the combustion equipment and energy system that delivers the defined service, including all fuels combusted to provide that service and the measurable service output or service driver used for normalization.
4.2 Boundary components
The project boundary shall include the stationary combustion equipment subject to the fuel switch and any associated fuel supply, metering, and control systems required to quantify fuel use for that equipment.
Where the combustion equipment supplies steam, heat, or energy to a defined process, the boundary shall include the measurement of the service output. Where direct service output measurement is not feasible, the boundary shall include measurement of an auditable service driver that is causally linked to energy demand and that can be applied conservatively for normalization.
Where multiple fuels are used during the monitoring period, including co-firing or partial substitution, the boundary shall include all fuels combusted in the relevant equipment and shall include monitoring sufficient to quantify each fuel’s contribution.
4.3 Greenhouse gases included
Baseline and project emissions shall include CO₂ and may include CH₄ and N₂O associated with fuel combustion, expressed in CO₂e, where required by PCS and where emission factors include those gases.
Where upstream emissions materially affect net reductions for the specific fuel switch and PCS requires their inclusion through leakage treatment, such upstream emissions shall be treated as leakage in Chapter 8 rather than as direct project boundary emissions, unless PCS specifies otherwise.
4.4 Inclusion of auxiliary energy use
Auxiliary electricity or fuel use that is directly attributable to enabling the fuel switch and is within the boundary of the service-delivering system shall be included where it is material and measurable. Such auxiliary loads may include fuel handling systems, pumps, compressors, heaters, or control systems required for the switched fuel.
Auxiliary energy use that is unrelated to the fuel switch or not causally linked to the service delivered shall not be included.
4.5 Boundary consistency and prevention of shifting
The boundary shall be defined to prevent shifting of baseline fuel use outside the boundary. Where the facility contains multiple boilers or heat sources, the project shall define the boundary such that baseline and project scenarios include the full set of equipment that serves the defined service, or otherwise demonstrate through metering and operational evidence that fuel switching does not result in increased use of baseline fuel in equipment outside the boundary to supply the same service.
Where the project proponent cannot demonstrate that service supply has not shifted to baseline-fuel equipment outside the boundary, conservative boundary expansion or conservative deductions shall be applied.
4.6 Treatment of service level and operating conditions
The boundary definition shall ensure that baseline and project scenarios represent the same service level. The project shall define and monitor the service metric such that reductions are not credited due to reduced service delivery, reduced production, lower operating hours, or other activity reductions.
Where operating conditions materially affect fuel consumption per unit service, the project shall account for such conditions through the baseline approach and normalization rules in Chapter 5.
4.7 Boundary exclusions
Upstream lifecycle emissions from manufacturing and construction of equipment are excluded. Emissions from unrelated facility activities not causally linked to the fuel switch are excluded.
The boundary shall not exclude any element where exclusion would result in over-crediting through unaccounted shifting of fuel use or unaccounted auxiliary energy use attributable to the fuel switch.
4.8 Boundary table
Table 4-1. Boundary sources and inclusion status (fuel switch)
Fuel combustion in switched equipment
Yes
Yes
Core emission source affected by fuel switch.
All fuels used in switched equipment
Yes
Yes
Prevents over-crediting under partial switching/co-firing.
Service output or service driver
Yes
Yes
Required for service equivalence and normalization.
Auxiliary energy use attributable to switch
Conditional
Conditional
Included where material and measurable.
Emissions from equipment outside boundary serving same service
Conditional
Conditional
Included if shifting risk exists and cannot be excluded credibly.
Upstream lifecycle emissions
No
No
Excluded under this methodology.
Unrelated facility emissions
No
No
Excluded to maintain causal relevance.
4.9 Documentation requirements
The project proponent shall provide boundary documentation sufficient for validation and verification. Documentation shall include a boundary narrative, identification of combustion equipment and fuel streams, metering points and measurement devices, definition of the service metric and its measurement approach, operational evidence demonstrating boundary consistency, and justification for any exclusions.
Failure to demonstrate an unambiguous and conservative boundary definition and auditable measurement of fuel use and service output 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 fuel use and associated emissions that would occur in the absence of the project activity while delivering the same useful energy output or industrial service. The baseline shall be defined in a transparent, conservative, and verifiable manner and shall not be selected or structured to inflate emission reductions.
Baseline and project scenarios shall be comparable in service level. Emission reductions shall not be claimed for reductions driven primarily by reduced service delivery, reduced production, curtailed activity, or unaccounted shifting of service supply.
5.2 Identification of the baseline scenario
The baseline scenario shall be identified by describing how the defined service would have been delivered in the absence of the fuel switch. The baseline shall normally be continued operation of the same equipment using the baseline fuel(s) historically used to deliver the service.
Where the project involves equipment conversion that changes efficiency, the baseline shall account for efficiency differences conservatively so that reductions are not overstated. Where conversion changes thermal efficiency in a manner that affects fuel consumption per unit service, baseline and project fuel use shall be compared on a useful output basis using the defined service metric and measured data.
Where the baseline includes a mix of fuels historically used, the baseline fuel mix shall be established using representative historical data and shall not be defined as a higher-emitting mix than supported by evidence.
5.3 Baseline period and representativeness
The project proponent shall define a baseline period and demonstrate that it is representative of normal operations for delivering the defined service. Baseline data shall be complete, auditable, and traceable to source records such as fuel invoices, meter logs, stock records, and service output records.
Where the baseline period includes abnormal events that materially bias baseline fuel consumption upward, the project proponent shall justify any exclusions and demonstrate that the resulting baseline remains conservative. Baseline manipulation through selective period choice is not permitted.
5.4 Service metric and normalization
Baseline emissions shall be determined on an equivalent service basis. The project shall define the service metric and shall measure it consistently in baseline and project periods.
The service metric shall be directly linked to the useful energy or industrial service delivered. Acceptable service metrics include steam output, useful heat delivered, electricity generated by on-site engines where relevant, or another auditable metric that allows like-for-like comparison.
Where direct measurement of useful heat delivered is not feasible, the project may use a conservative proxy service driver that is causally linked to energy demand, provided that the proxy is auditable and that it does not inflate baseline emissions.
Baseline fuel consumption for monitoring period shall be determined in a manner that reflects the service level delivered in period . Where output varies, baseline fuel use shall be normalized to the monitored service output in period using baseline fuel intensity per unit service.
5.5 Baseline fuel consumption determination
Baseline fuel consumption for monitoring period shall be determined for each baseline fuel used to deliver the defined service.
Where a historical performance baseline is used, baseline fuel intensity per unit service shall be derived from the baseline period and applied to the monitored service output in monitoring period . Where baseline operations include multiple fuels, baseline fuel intensity shall reflect the baseline fuel mix evidenced in the baseline period.
Benchmark baselines shall not be used unless PCS explicitly allows them for fuel switching and the benchmark is credible, applicable, and conservative relative to historical performance.
5.6 Baseline emissions calculation
Baseline emissions shall be calculated by multiplying baseline fuel consumption by the relevant emission factors, including CO₂ and where required CH₄ and N₂O, expressed in CO₂e.
Table 5-1. Baseline emissions equations
Fuel combustion
Where:
is baseline emissions in monitoring period 
(tCO₂e).
is baseline consumption of baseline fuel 
in monitoring period (fuel units).
is emission factor for baseline fuel (tCO₂e/fuel unit), including any required non-CO₂ components and consistent unit conversions..
Where baseline fuel consumption is derived from baseline fuel intensity per unit service, the project shall document the derivation and application to the monitored service output.
5.7 Baseline validity, updating, and material changes
Baseline parameters shall remain valid only where they continue to represent baseline delivery of the defined service. Where material changes occur that affect service demand, equipment configuration, fuel availability, operational constraints, or the baseline fuel mix, the project proponent shall apply conservative baseline adjustments or baseline re-establishment consistent with PCS procedures.
Where regulations or enforceable policies mandate fuel switching or constrain baseline fuel availability during the crediting period, the baseline shall be updated conservatively to reflect those constraints and the project shall not credit reductions that would occur due to mandated changes absent the project.
5.8 Documentation requirements
The project proponent shall document baseline scenario identification, baseline period selection, representativeness assessment, service metric definition and measurement, normalization approach, baseline fuel consumption determination, emission factor selection, and any adjustments applied.
Documentation shall include baseline datasets and source records, service output records, evidence supporting baseline fuel mix, and calculation files sufficient for independent replication.
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 fuel switch would not have occurred as implemented, would not have been implemented at the same scale and timing, or would not have delivered the same verified emission reductions.
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 fuel switch is legally mandated, required by an enforceable permit condition, required by a binding sectoral obligation, or required by an enforceable fuel standard applicable to the facility or equipment.
The project proponent shall identify all applicable policies, standards, and permit conditions relevant to the baseline fuel, project fuel, and the affected equipment. Where policies exist that restrict baseline fuel use, mandate phase-out, impose fuel quality requirements, or require specific emissions performance levels, the project proponent shall demonstrate that credited reductions exceed compliance and are not simply the result of policy.
Where a legally binding phase-out or mandatory transition applies during the crediting period, the project shall not claim reductions that would occur due to the mandated timeline absent the project, and baseline assumptions shall be updated conservatively.
6.3 Investment analysis or barrier analysis
The project proponent shall demonstrate additionality using either an investment analysis or a barrier analysis, supported by auditable evidence that reflects information available at the time of the decision to implement the fuel switch.
6.3.1 Investment analysis
Where investment analysis is applied, the project proponent shall demonstrate that the fuel switch 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 include capex for conversion, burners, safety systems, storage, pipelines, and metering; opex impacts; maintenance impacts; expected changes in fuel costs and fuel supply reliability; any changes in efficiency; downtime and commissioning costs; and any incentives, subsidies, or rebates received.
The project shall not omit material benefits or support mechanisms that would materially affect the conclusion. Sensitivity analysis shall be conducted on material parameters, including fuel price spreads and expected utilisation. Conservative assumptions shall be applied so that the role of carbon revenue is not overstated.
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 fuel switch in the absence of carbon revenues and that the project overcomes the identified barrier(s).
Barrier claims may include limited access to finance, high conversion cost, fuel supply infrastructure constraints, contractual lock-in for baseline fuel, technology and safety risk, operational disruption risk, or institutional constraints. Claims shall be facility-specific, evidenced, and causally linked to the implementation decision. Generic claims that “fuel switching is hard” without evidence shall not be accepted.
6.4 Common practice assessment
The project proponent shall assess whether the fuel switch and the achieved emissions performance are common practice in the applicable context, considering relevant geography, sector, equipment type, and regulatory environment.
If the same fuel switch is already widely implemented for similar facilities under similar conditions without carbon finance, the project shall not be eligible unless the project proponent demonstrates material differences that affect the likelihood of implementation and are not driven by legal requirements.
6.5 Timing integrity and prior consideration
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 fuel switch is implemented, commissioned, or financially closed prior to entering PCS, the project proponent shall demonstrate eligibility under PCS rules applicable to start date and prior consideration and shall not claim reductions for periods that do not meet PCS timing requirements.
6.6 Additionality failure conditions
A project shall be deemed not additional where the fuel switch is legally mandated, where the investment analysis demonstrates strong financial attractiveness without carbon revenue and the project cannot show carbon revenue is decisive, where claimed barriers are not supported by facility-specific evidence, where the switch is common practice without credible differentiation, or where timing and prior consideration requirements are not met.
6.7 Documentation requirements
The project proponent shall provide documentation sufficient for validation. Documentation shall include the regulatory analysis, the selected additionality demonstration method and supporting evidence, 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.
For fuel switching, project emissions primarily arise from combustion of the project fuel(s) used to deliver the defined service. Where multiple fuels are used in the project scenario, project emissions shall include emissions from each fuel combusted in the boundary equipment.
This methodology does not quantify removals. No removals shall be claimed under PCS-TR-010.
7.2 Project fuel consumption determination
Project fuel consumption for monitoring period shall be determined using monitored data for each fuel combusted in the boundary equipment.
Fuel quantities shall be measured using suitable meters or auditable fuel balance approaches. Where purchase records are used, reconciliation to stock changes and operational use shall be performed to prevent understatement of fuel use.
Where the project involves co-firing or partial substitution, the project shall quantify fuel consumption separately for each fuel used and shall not assume substitution shares without evidence.
7.3 Fuel properties and emission factors
Project emissions shall be calculated using emission factors appropriate to each project fuel, including required non-CO₂ components where applicable.
Where emission factors depend on fuel properties such as net calorific value, carbon content, or methane slip, the project proponent shall determine such properties using conservative and auditable methods. Where fuel properties vary materially over time, the project shall apply a sampling and testing plan sufficient to reflect variation conservatively.
Emission factor selection shall be consistent across baseline and project scenarios and shall not be selected to inflate emission reductions.
7.4 Project emissions calculation
Project emissions shall be calculated by multiplying monitored project fuel consumption by the relevant emission factors, expressed in CO₂e.
Table 7-1. Project emissions equations
Fuel combustion
Where:
is project emissions in monitoring period (tCO₂e).
is project consumption of fuel 
in monitoring period (fuel units).
is emission factor for project fuel (tCO₂e/fuel unit), including required non-CO₂ components and consistent unit conversions.
Where auxiliary electricity or energy use attributable to the switch is included in the boundary, associated emissions shall be included in project emissions using applicable electricity or fuel emission factors and measured consumption.
7.5 Treatment of efficiency changes and service output
Fuel switching may alter combustion efficiency and therefore fuel consumption per unit service. This methodology treats such effects through measured fuel consumption and service equivalence requirements.
Project emissions shall be based on monitored fuel use for the delivered service. The project shall not claim reductions that arise from reduced service output. Where service output changes, baseline determination and normalization shall ensure like-for-like comparison.
7.6 Excluded project emissions
Upstream lifecycle emissions from manufacturing and construction are excluded. Upstream fuel supply emissions are not included as direct project emissions under this chapter and are addressed, where applicable, as leakage under Chapter 8.
7.7 Documentation requirements
The project proponent shall document the determination of project fuel consumption, fuel measurement approach, fuel property determination where required, emission factor selection, auxiliary energy use inclusion where applicable, and calculation procedures. Documentation shall include source records such as meter datasets, fuel invoices, stock reconciliation, fuel sampling and test reports where used, and calculation files sufficient for independent replication.
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.
For fuel switching projects, leakage risk is commonly associated with upstream fuel supply chain emissions, including methane leakage for gaseous fuels, emissions from fuel processing and transport, and emissions and sustainability risks associated with biomass fuels. Leakage may also occur through shifting of baseline fuel use to equipment outside the boundary to supply the same service.
8.2 Leakage assessment requirement
The project proponent shall assess leakage based on the fuel switch type, fuel supply arrangements, and facility context. Leakage assessment is mandatory. Where leakage sources are plausible and material, leakage shall be quantified conservatively and deducted from emission reductions.
Where leakage cannot be quantified credibly and the risk is material, the project shall apply conservative deductions up to and including zero issuance for the affected monitoring period where environmental integrity cannot be established.
8.3 Leakage sources and treatment
8.3.1 Upstream methane leakage for natural gas and other gaseous fuels
Where the project fuel is natural gas, LNG, CNG, or another gaseous fuel for which upstream methane leakage is material, the project proponent shall assess and quantify upstream methane leakage emissions attributable to the incremental use of the project fuel.
Quantification shall use an approved PCS approach or conservative default factors where PCS recognises such defaults. Where multiple credible upstream leakage factors exist, the project shall apply a conservative factor that avoids over-crediting.
Where project fuel supply is demonstrably from a supply chain with verified lower methane intensity, such evidence may be used only where it is independently verifiable and does not introduce over-crediting through selective claims.
8.3.2 Upstream processing and transport emissions
Where upstream processing, compression, liquefaction, transport, or distribution emissions are material for the project fuel relative to the baseline fuel, and where PCS requires inclusion, the project shall quantify such emissions as leakage using conservative factors or verified data.
The project shall not include speculative upstream benefits that cannot be verified.
8.3.3 Biomass and biofuel leakage and sustainability risks
Where the project fuel is biomass, biogas, biofuel, or a waste-derived fuel, the project proponent shall assess leakage risks including indirect effects on biomass availability, diversion of biomass from existing uses, land-use change risk, and supply chain emissions.
Where sustainability and additionality of biomass supply cannot be demonstrated in accordance with PCS requirements, the project shall not be eligible for issuance for the affected fuel portion.
Where PCS requires specific safeguards or sourcing criteria for biomass fuels, those requirements shall be met and evidenced. Where quantification of leakage is required, conservative approaches shall be applied.
8.3.4 Shifting of baseline fuel use outside the boundary
Leakage may occur where the facility increases use of baseline fuel in equipment outside the boundary to supply the same service due to boundary definition choices.
Where such shifting is plausible, the project shall implement monitoring and operational controls sufficient to demonstrate that service delivery has not shifted to baseline-fuel equipment outside the boundary. Where shifting cannot be excluded credibly, conservative boundary expansion or conservative leakage deductions shall be applied.
8.4 Leakage quantification
Where quantified, leakage emissions for monitoring period shall be calculated and deducted from emission reductions.
Table 8-1. Leakage accounting structure
Upstream fuel emissions
Shifting leakage
determined conservatively where applicable
Total leakage
Where:
is the upstream leakage emission factor for project fuel , expressed in tCO₂e per unit fuel, applicable to the relevant supply chain and period, and selected conservatively.
Where upstream leakage is not required by PCS for a specific fuel type, the project shall document the assessment and justify exclusion.
8.5 Documentation requirements
The project proponent shall document leakage assessment, inclusion or exclusion rationale, data sources and assumptions, upstream emission factor selection, supply chain evidence where used, 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.
Emission reductions shall represent reduced emissions per unit of the defined service delivered and shall not be claimed for reductions driven primarily by reduced service output, reduced production, or unaccounted shifting of baseline fuel use outside the boundary.
9.2 Net emission reductions
Net emission reductions for monitoring period shall be calculated as follows.
Table 9-1. Net emission reduction equation
Net emission reductions
Where:
is emission reductions in monitoring period (tCO₂e).
is baseline emissions in monitoring period (tCO₂e), determined in Chapter 5 on an equivalent service basis and normalized where required.
is project emissions in monitoring period (tCO₂e), determined in Chapter 7 using monitored project fuel consumption.
is leakage emissions in monitoring period (tCO₂e), determined in Chapter 8, including upstream leakage where applicable.
Emission reductions shall not be claimed for periods in which 
. Where 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, leakage factor updates, 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 Treatment of multiple fuels and partial switching
Where multiple fuels are combusted during the monitoring period, emission reductions shall be calculated using the monitored fuel quantities for each fuel. The project shall not assume full switching. Co-firing and partial substitution shall be quantified explicitly and shall not be credited beyond the fraction of service delivered using the lower-emitting fuel, after accounting for all relevant emissions and leakage.
9.5 Treatment of multiple electricity systems and auxiliary energy
Where auxiliary electricity consumption attributable to the switch is included in the boundary and the electricity system differs from the service location or varies across the project, the project shall apply applicable emission factors and disaggregate where required to avoid over-crediting.
9.6 Rounding and units
Fuel quantities shall be expressed in the units used by monitored sources, with explicit conversion factors and net calorific values where needed. 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.
9.7 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, including policy-driven baseline changes and supply chain changes that affect leakage.
9.8 Documentation requirements
For each monitoring period, the project proponent shall provide a complete calculation record that includes baseline emissions, project emissions, leakage emissions, net emission reductions, service output or service driver records used for normalization, emission factor sources, fuel property data where applicable, 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, leakage where applicable, and net emission reductions for each monitoring period. Monitoring shall enable independent verification of fuel quantities, fuel characteristics where required, service output or service driver data used for normalization, and boundary consistency.
Monitoring shall be implemented as a system. The system shall include measurement hardware, data collection and storage procedures, QA/QC controls, calibration and maintenance arrangements, reconciliation checks, 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 boundary and fuel switch configuration. Where a parameter is not applicable, the project proponent shall justify non-applicability and demonstrate that exclusion does not result in over-crediting.
Table 10-1. Monitoring parameters (minimum)
(FC^{PJ}_{j,t})
Project fuel consumption of fuel (j) in period (t)
Fuel unit
All projects
Continuous/event-based; aggregated per period
Fuel flow meters, custody transfer meters, tank logs, purchase and stock reconciliation
Calibration; reconciliation; plausibility checks
Baseline fuel use evidence
Evidence supporting baseline fuel consumption/intensity
N/A
All projects
Baseline establishment; updates if required
Invoices, meter logs, stock records, operating logs
Completeness and representativeness checks
Service output (S_{t})
Useful service delivered in period (t)
Facility unit
All projects
Continuous/daily; aggregated per period
Steam meters, heat meters, production records, validated proxies
Cross-checks; consistency controls
Fuel properties
NCV, carbon content, composition where required
Various
Where variable fuel quality is material
Per batch or periodic per plan
Lab tests, supplier certificates, sampling
Chain-of-custody; conservative treatment
Emission factors
(EF_{FUEL}), non-CO₂ where required
tCO₂e/unit
All projects
At least annually or per update
Authoritative sources
Version control; applicability
Upstream leakage factor (UF_{j})
Upstream emissions factor for fuel (j)
tCO₂e/unit
Where required
Per period or per update
PCS-approved factor or conservative default
Applicability; conservative selection
Auxiliary energy use
Electricity/fuel attributable to switch
kWh/fuel unit
Conditional
Continuous/event-based
Meters, logs, invoices
Reconciliation; materiality check
Meter register
List and IDs of meters and locations
N/A
All projects
At commissioning and when changed
Register and diagrams
Change control
Calibration records
Calibration and accuracy evidence
N/A
All projects
Per standard; at least annually unless stricter
Certificates; maintenance logs
Traceability; corrective actions
10.4 Fuel measurement requirements
Fuel consumption shall be measured using suitable meters or auditable fuel balance approaches. Where flow metering is used, meters shall be installed such that they capture all fuel supplied to the boundary equipment. Where shared fuel supply lines exist, the project shall implement metering or allocation methods that are auditable and conservative.
Where purchase records are used as primary evidence, the project shall perform reconciliation to stock changes and operational use. Purchase-only approaches without stock reconciliation are not acceptable where they would risk understatement.
For gaseous fuels, custody transfer metering and pressure/temperature compensation shall be addressed where relevant. For liquid fuels, density and temperature correction shall be addressed where relevant. For solid fuels, mass measurement and moisture content treatment shall be addressed where relevant.
10.5 Service output measurement and normalization integrity
The project shall measure the defined service output or service driver used for normalization. Measurement shall be consistent across monitoring periods and shall reflect equivalent service delivery between baseline and project scenarios.
Where a proxy service driver is used, the proxy shall be auditable and causally linked to energy demand. The project shall document the relationship and demonstrate that the proxy does not inflate emission reductions. Where the relationship changes due to operational changes, conservative adjustments shall be applied.
10.6 Fuel quality monitoring
Where fuel emission factors depend on variable fuel properties and such variability is material, the project shall implement a fuel sampling and testing plan. The plan shall define sampling frequency, sampling locations, chain-of-custody, test methods, and conservative treatment of missing or failed tests.
Where supplier certificates are used, the project shall demonstrate that certificates are applicable to delivered batches and are traceable. Where certificates are not available or not credible, conservative defaults shall be applied.
10.7 Data quality and QA/QC
Monitoring data shall be subject to QA/QC controls sufficient to ensure accuracy and integrity. 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 fuel metering totals to purchase and stock records, plausibility checks comparing fuel use to service output, and investigation of anomalies.
10.8 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.
Where project fuel consumption data are missing, conservative substitution shall not result in lower project fuel consumption than would be supported by evidence. Where service output data are missing, conservative treatment shall prevent crediting reductions driven by unverified service delivery. Where fuel property data are missing and variability is material, conservative fuel property values shall be applied that do not increase claimed reductions.
Where credible conservative quantification cannot be demonstrated for the affected period, the project shall apply conservative deductions up to and including zero issuance for the affected monitoring period.
All data gaps and treatments shall be documented with the period affected and the impact on results.
10.9 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.
10.10 Monitoring report content
For each monitoring period, the project proponent shall prepare a monitoring report that includes the monitoring period definition and operational summary, fuels used and quantities, service output records, fuel property data where applicable, emission factor sources and updates, upstream leakage factors where applicable, boundary consistency confirmation, data QA/QC, data gaps and conservative treatments, leakage assessment and quantification, and the 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 Identification of uncertainty sources
The project proponent shall identify and document the sources of uncertainty that may materially affect baseline emissions, project emissions, leakage, and net emission reductions.
For fuel switching projects, uncertainty commonly arises from fuel quantity measurement accuracy, incomplete capture of fuel supplied to boundary equipment, fuel stock reconciliation errors, variable fuel properties and sampling limitations, emission factor selection and unit conversion errors, service output measurement errors and proxy validity, boundary shifting to non-monitored equipment, partial switching assumptions, and upstream leakage factor uncertainty for gaseous fuels and biofuels.
Only uncertainty sources that affect the quantified difference between baseline and project emissions for the defined service shall be considered for conservative treatment under this methodology.
11.3 Fuel quantity measurement uncertainty
Fuel quantities used for quantification shall be supported by auditable measurements and reconciliation checks. Meters shall be calibrated and maintained, and the project shall demonstrate meter integrity for the monitoring period.
Where meter accuracy is degraded, calibration is overdue, integrity cannot be demonstrated, stock reconciliation is incomplete, or data are inconsistent, the project proponent shall apply conservative treatment to the affected data. Conservative treatment shall not result in lower quantified project fuel consumption or higher quantified baseline fuel consumption than would be supported by credible evidence.
Where multiple measurement sources exist, the project shall reconcile datasets and resolve discrepancies conservatively.
11.4 Fuel property uncertainty
Where emission factors depend on fuel properties such as net calorific value, carbon content, or composition and such variability is material, the project shall apply conservative treatment where tests are missing, sampling is inadequate, or certificates are not credible.
Conservative treatment shall not result in lower project emissions or higher baseline emissions than would be supported by credible evidence. Where uncertainty persists, the project shall apply conservative default values that reduce claimed emission reductions.
11.5 Service output and normalization uncertainty
The service metric is the control against crediting reductions from reduced output. The project shall ensure that service output data are auditable and measured consistently.
Where a proxy service driver is used, uncertainty in the relationship between the proxy and useful service shall be treated conservatively. The project shall not claim reductions where the proxy relationship is not stable or cannot be verified.
Where service output data are missing or unreliable for a period, the project shall apply conservative outcomes that prevent over-crediting, up to and including zero issuance for the affected period where integrity cannot be established.
11.6 Baseline representativeness uncertainty
Baseline determination shall rely on representative data. Where baseline period selection, baseline fuel mix, baseline fuel intensity derivation, or baseline service conditions are uncertain, the project proponent shall apply conservative baseline choices that do not increase credited reductions.
Where material changes occur that affect baseline comparability, the project shall apply conservative baseline adjustments or baseline re-establishment consistent with PCS procedures.
11.7 Upstream leakage uncertainty
Where upstream leakage is included, uncertainty in upstream factors shall be treated conservatively. The project shall not select upstream leakage factors, boundaries, or temporal windows to reduce leakage deductions and inflate reductions.
Where credible supply-chain-specific data are not available, the project shall apply conservative default upstream leakage factors consistent with PCS requirements. Where uncertainty is high, conservative deductions shall be applied.
11.8 Data gaps and estimation
Data gaps increase uncertainty. Gap-filling shall follow the conservative rules in Chapter 10 and shall not increase credited reductions.
Where credible conservative quantification cannot be demonstrated, the project shall apply conservative deductions up to and including zero issuance for the affected monitoring period.
Any estimation method that materially increases emission reductions shall require explicit justification and may be rejected at verification.
11.9 Documentation requirements
The project proponent shall maintain documentation sufficient for validation and verification. Documentation shall include meter specifications and calibration records, fuel measurement and reconciliation procedures, fuel property sampling and test records, service output measurement records and proxy justification where applicable, baseline representativeness assessment and any adjustments, emission factor sources and update records, upstream leakage factor sources and justification where applicable, and records of data gaps 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 eligibility, baseline integrity, service equivalence, boundary consistency, monitoring integrity, fuel property treatment, upstream leakage treatment, emission factor applicability, 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
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. The VVB shall assess whether the service metric is appropriate and measurable, whether the baseline scenario and baseline period are credible and representative, whether the boundary definition prevents shifting, whether monitoring is feasible for fuel quantities and service output, and whether fuel property determination and leakage assessment are adequate.
The VVB shall assess whether the fuel switch is a full conversion or partial substitution and whether the project design and monitoring approach can quantify multiple fuels without over-crediting.
12.3 Validation checks on eligibility and applicability
The VVB shall confirm that the project is within scope and that exclusion triggers do not apply. The VVB shall verify legal compliance and required permits for fuel switching, equipment modifications, safety systems, and operation.
The VVB shall verify the project start date and assess prior consideration requirements where applicable. The VVB shall assess the project proponent’s right to claim emission reductions and evaluate overlap risks with government incentives, utility programs, compliance obligations, and other mechanisms.
For projects involving gaseous fuels or biomass fuels, the VVB shall assess whether leakage requirements and safeguards applicable under PCS can be met.
12.4 Validation checks on boundary definition and prevention of shifting
The VVB shall assess whether the boundary definition is unambiguous and captures all fuels combusted to deliver the defined service. The VVB shall verify metering points and confirm that fuel consumption monitoring captures fuel supplied to the boundary equipment.
Where the facility has multiple heat sources or service supply pathways, the VVB shall assess the risk of shifting baseline fuel use to equipment outside the boundary. Where shifting is plausible, the VVB shall require boundary expansion, additional monitoring, or conservative leakage deductions.
The VVB shall assess the inclusion of auxiliary energy use attributable to the switch where it is material.
12.5 Validation checks on baseline scenario and baseline determination
The VVB shall assess baseline scenario identification and confirm that it reflects the most plausible service delivery absent the project. The VVB shall assess baseline period selection and representativeness, including the completeness and auditability of baseline fuel and service datasets.
The VVB shall assess the derivation of baseline fuel intensity per unit service where normalization is applied and confirm that the approach prevents crediting reductions due to reduced service output.
The VVB shall verify baseline emission factor selection, including unit conversions and treatment of non-CO₂ emissions where applicable.
12.6 Validation checks on service metric integrity
The VVB shall verify that the service metric is well-defined, measurable, and causally linked to the fuel use in the boundary equipment. Where proxies are used, the VVB shall assess whether the proxy relationship is credible, stable, and conservative.
The VVB shall confirm that the project can monitor the service metric consistently across monitoring periods and that material changes will be detected and managed.
12.7 Validation checks on additionality
The VVB shall assess the additionality demonstration for completeness and credibility. The VVB shall confirm that the fuel switch is not legally mandated and assess policy interactions, including subsidies and sectoral obligations.
Where investment analysis is used, the VVB shall assess whether all material costs and benefits are included, including fuel price spreads, incentives, and efficiency impacts. Where barrier analysis is used, the VVB shall assess whether barriers are facility-specific and evidenced.
The VVB shall assess the common practice assessment and confirm that the applicable context is appropriate and that conclusions are supported by evidence.
12.8 Verification scope
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.
The VVB shall verify that the boundary, equipment configuration, fuels used, service metric definition, and monitoring system have not changed in a manner that affects baseline comparability, boundary consistency, or quantification without appropriate PCS approval.
12.9 Verification checks on monitoring data integrity and reconciliation
The VVB shall verify monitored fuel consumption for each fuel used and shall reconcile metered quantities against purchase records and stock changes. The VVB shall assess whether fuel measurement covers all boundary equipment and whether any unmonitored supply routes exist.
The VVB shall verify service output records and confirm that service delivery is consistent with assumptions and that emission reductions are not driven by reduced output. Where proxies are used, the VVB shall verify proxy datasets and assess whether the proxy relationship remains valid.
The VVB shall verify calibration records and meter integrity for the monitoring period and assess whether any measurement issues require conservative adjustments.
12.10 Verification checks on fuel properties and emission factors
The VVB shall verify fuel property data and sampling records where applicable and confirm that fuel property values applied are representative and conservative. Where supplier certificates are used, the VVB shall verify applicability and traceability.
The VVB shall confirm that emission factors applied for baseline and project fuels are applicable to the monitoring period and are not selected to increase credited reductions.
12.11 Verification checks on leakage treatment
Where upstream leakage is included, the VVB shall verify the upstream factors applied, confirm that the factors are applicable and conservative, and confirm that the leakage deduction is calculated correctly based on monitored project fuel use.
Where boundary shifting leakage is plausible, the VVB shall verify operational evidence and monitoring sufficient to exclude shifting or apply conservative leakage deductions where shifting cannot be excluded.
12.12 Verification checks on calculation accuracy
The VVB shall reproduce emission reduction calculations using verified inputs and shall confirm correct equations, units, aggregation, and deductions. The VVB shall confirm that emission reductions are not claimed for periods with zero or negative results and that rounding is conservative.
The VVB shall verify that data gaps and conservative treatments are applied as required and that any estimation does not increase credited reductions.
12.13 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 boundary definition, baseline datasets, fuel property treatment, leakage factors, service metric datasets, emission factor selection, or calculation methods, the VVB shall verify revised materials and confirm that revisions do not introduce over-crediting.
12.14 Common failure conditions under this methodology
A project shall be treated as having a material integrity failure where the VVB determines that baseline representativeness cannot be established, where boundary shifting cannot be excluded, where fuel consumption monitoring is incomplete or not auditable, where service output cannot be verified, where fuel properties are not supported and materially affect emissions, or where leakage deductions are not applied conservatively when required.
Where integrity cannot be established for a monitoring period, the VVB shall apply conservative outcomes up to and including zero issuance for the affected period.
12.15 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, conversion factors, fuel property assumptions, upstream leakage factors where applicable, 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 the 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
This methodology relies on minimum reference categories where applicable. PCS documents apply, including the relevant PCS standards, this methodology, any referenced PCS methodological tools, and applicable PCS templates and forms. Host country laws and regulations apply where they affect fuel switching, combustion equipment, safety, environmental permitting, and fuel quality.
Authoritative combustion emission factor references apply for baseline and project fuels, including recognised guidance on CO₂, CH₄, and N₂O factors and unit conversions. Official electricity emission factor publications apply where auxiliary electricity is included. Recognised technical standards for fuel metering, calibration, and measurement accuracy apply to all measurement systems used. Authoritative sources relevant to upstream fuel supply emissions apply where PCS requires inclusion of upstream leakage deductions.
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 dataset is updated periodically, the project proponent shall retain the specific version used for each monitoring period and demonstrate consistency with update requirements. Fuel property evidence, including certificates and laboratory reports, shall be retained with batch traceability where applicable.
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.
Table A-1. Parameters (minimum)
(FC^{PJ}_{j,t})
Project fuel consumption of fuel (j) in period (t)
Fuel unit
All projects
Flow meters, custody meters, tank logs, purchase + stock reconciliation
Continuous/event-based; aggregated per period
No
(FC^{BL}_{i,t})
Baseline fuel consumption of fuel (i) in period (t) on equivalent service basis
Fuel unit
All projects
Baseline intensity applied to monitored service output; or other PCS-allowed approach
Per period
No
(S_{t})
Service output in period (t)
Facility unit
All projects
Steam meters, heat meters, validated proxies
Continuous/daily; aggregated
No
(EF_{FUEL,i})
Emission factor for baseline fuel (i)
tCO₂e/fuel unit
All projects
Authoritative sources; unit conversions documented
Update as required
Yes, if authoritative published factors are used
(EF_{FUEL,j})
Emission factor for project fuel (j)
tCO₂e/fuel unit
All projects
Authoritative sources; unit conversions documented
Update as required
Yes, if authoritative published factors are used
Fuel properties
NCV, carbon content, composition
Various
Where variable properties are material
Lab tests or supplier certs with traceability
Per batch or periodic per plan
Limited; conservative defaults only where allowed
(UF_{j})
Upstream leakage factor for project fuel (j)
tCO₂e/fuel unit
Where required
PCS-approved default or conservative factor
Per period or per update
Limited; PCS-recognised defaults only
Auxiliary energy use
Electricity/fuel attributable to switch
Various
Conditional
Meters, invoices, logs
Continuous/event-based
No
Annex B - Worked Example
B.1 Example purpose and limitations
This worked example is illustrative and demonstrates calculation logic. Project proponents shall use project-specific monitored data, service-normalized baselines, applicable emission factors, and required leakage deductions.
B.2 Example scenario and inputs
Assume a boiler switches from heavy fuel oil (baseline) to natural gas (project) to produce steam. Steam output is used as the service metric. Baseline fuel intensity is established from a representative baseline period. The monitoring period is one year.
Upstream leakage is included for the project gas fuel using a conservative upstream factor for illustration.
Table B-1. Example inputs for monitoring period
Steam output 
500,000 tonnes steam
Monitored
Baseline fuel intensity
0.070 t HFO / t steam
Derived from baseline period
Project natural gas consumption 
28,000,000 Nm³
Metered
HFO emission factor 
0.00320 tCO₂e / kg HFO
Example only
NG emission factor 
0.00190 tCO₂e / Nm³
Example only
Upstream factor 
0.00020 tCO₂e / Nm³
Example only
B.3 Baseline fuel consumption and baseline emissions
Convert 35,000 t to kg: 35,000,000 kg.
B.4 Project emissions
B.5 Leakage emissions (upstream)
Assume shifting leakage is zero for the example.
B.6 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)
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
Boundary equipment ID(s)
Boilers/furnaces/etc.
Text
Yes
Baseline fuel(s)
Fuel type(s)
Text
Yes
Project fuel(s)
Fuel type(s)
Text
Yes
Fuel meter ID(s)
Meter identifiers
Text
Yes
Project fuel consumption 
Period total by fuel
Fuel units
Yes
Baseline intensity value(s)
Baseline fuel per unit service
Unit
Yes
Service metric definition
Steam/heat/etc.
Text
Yes
Service output
Period total service output
Facility unit
Yes
Baseline fuel consumption 
Period baseline fuel by fuel
Fuel units
Yes
Fuel property evidence refs
Certificates/tests and batch IDs
Text
Conditional
Emission factor source/version
Baseline and project EF source
Text
Yes
Upstream factor source/version
where applicable
Text
Conditional
Baseline emissions 
tCO₂e
Yes
Project emissions 
tCO₂e
Yes
Leakage emissions 
tCO₂e
Conditional
Net reductions 
tCO₂e
Yes
Auxiliary energy included
Yes/No
Text
Conditional
Auxiliary energy amount
kWh/fuel unit
Conditional
Calibration certificate refs
References
Text
Yes
Data gaps present
Yes/No
Text
Yes
Gap treatment description
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.2 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.
Baseline emissions (BE_t) means the GHG emissions that would occur in monitoring period t in the absence of the project activity, associated with baseline fuel combustion required to deliver the same defined service.
Baseline fuel means the fuel or fuel mix that would have been combusted to deliver the defined service in the absence of the project activity.
Baseline fuel intensity means baseline fuel consumption per unit of defined service output, derived from a representative baseline period and applied for normalization where required.
Boundary means the defined combustion equipment, fuels, and service output measurement included for quantification under this methodology.
Co-firing means simultaneous combustion of more than one fuel in the same equipment to deliver the defined service.
Fuel switch means the replacement or substitution of a baseline fuel with a project fuel in defined equipment while delivering the same useful energy output or service.
Fuel properties means fuel characteristics affecting emissions and conversions, including net calorific value, carbon content, moisture content, density, or composition, as applicable.
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.
Partial substitution means the use of a project fuel for only a portion of the service delivered, with the remaining portion supplied using baseline fuel or other fuels.
Project emissions (PE_t) means GHG emissions occurring within the project boundary in monitoring period t that are attributable to the project scenario, primarily from combustion of the project fuel(s) used to deliver the defined service.
Service metric (S_t) means the measurable output representing the useful energy or industrial service delivered during monitoring period t, used to ensure like-for-like comparison between baseline and project scenarios.
Shifting leakage means leakage that occurs where baseline fuel use increases outside the defined boundary to supply the same service due to project boundary definition choices.
Upstream leakage factor (UF_j) means the emissions factor representing upstream supply chain emissions attributable to the project fuel , used to quantify leakage where required.
D.2 Acronyms
Table D-1. Acronyms
BE
Baseline Emissions
EF
Emission Factor
ER
Emission Reductions
GHG
Greenhouse Gas
LE
Leakage Emissions
NCV
Net Calorific Value
PE
Project Emissions
PCS
Planetary Carbon Standard
PCC
Planetary Carbon Credit
QA/QC
Quality Assurance / Quality Control
VVB
Validation and Verification Body
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