Reporting scope 2 emissions: the GHGP's new consultation

What does the Greenhouse Gas Protocol's (GHGP) consultation mean for your business?

28 November 2025 Hannah Simmonds and Beth Bentley, experts in corporate decarbonisation

Context

The current global standard for how companies report their emissions - set by the Greenhouse Gas Protocol, an independent standards authority - has long been criticised for enabling uncredible claims to Scope 2 emission reduction. The criticisms centre on three main topics: 

Traceability

Renewable power certificates that organisations use to report market-based scope 2 emissions can be purchased separate to the power and only ‘matched’ on an annual basis, meaning there is little or no link between when renewable power is generated and when it is consumed

Additionality

There is no proven link between purchased renewable certificates and additional renewable deployment, meaning it does not contribute to accelerated grid decarbonisation

Market boundaries

Current standards dictate that these certificates need to be sourced from the ‘same market’ to where the reporting entity is located. This broad definition has led to sourcing of certificates from more renewable grid regions to cover power consumption in comparatively dirtier grids (i.e. a Data Centre in Georgia buying cheaper California solar certificates, or in Poland buying Spanish solar certificates) 

The standards currently require corporates to report both their location-based emissions, those based on the average annual emissions intensity of the grid where they operate, and market-based emissions, calculated via purchased power volumes.  

Recognising the call for change, the GHGP started a revision process in 2022 to update the standards, creating a more robust framework that aims to drive greater decarbonisation. The latest Consultation released in October 2025 outlines some major proposed changes to reporting methods and will likely bring in a new age of corporate renewable procurement. 

What does this mean for me?

The consultation outlines three main changes to emissions reporting

These changes demonstrate a move to drive a closer link between the power consumption of organisations and the renewables they procure, as well as recognising system-wide benefits of investments that decarbonise grids around the world:

Location based

Increase locational granularity

 

Aim 

Strengthening the relationship between the local grid emissions and company demand.

Application 

Feasibility 

Introduce a requirement for location-based emissions to use the most precise location-based emissions factor accessible and available: 

  • Spatial precision first (local, regional, national, continental) 
  • Then temporal granularity (hourly, monthly, annual) 
  • Consumption-based factors over production-based (factors that include imports/exports are prioritised) 

New definition introduced for ‘accessible’ or ‘available’ emissions factors: 

  • Accessible or Available: publicly available, free to use, and from a credible source 
  • Organisations are not required to use proprietary or paid emission factor databases
  • This balances accuracy improvements with feasibility for all organisation sizes

The spatial emissions factors will depend on companies having access to the most precise locational emission factor data, which may not be accessible or consistent across geographies.

 

Impact 

Outstanding Questions 

This should drive greater consideration by organisations of the location and time of their demand. When combined with SBTi’s new requirements to set both location and market based emissions targets, this should encourage more consideration for choosing locations with higher renewables penetration (e.g. California, Spain) and shifting demand where possible to times of higher renewable generation. 

This will primarily affect developed markets and grids where more granular emissions data is available.

With growing interconnection across neighboring markets, it is unclear how the hierarchy will apply for imported power, although it will likely just be covered as part of the grid emissions factor. 

It is also unclear how this will affect battery assets, namely how battery export to the grid will be treated, i.e. will this contribute to decarbonising a Scope 2 position and eligible for certificates, or is this to be captured by the consequential method. 

Hourly reporting

 

Aim 

Strengthening the relationship between the time of grid generation and company demand.

Application 

Feasibility 

Introduce a requirement for location-based emissions to use the most precise temportal location-based emissions factor accessible and available: 

  • Hourly, monthly, annual granularity hierarchy

New definition introduced for ‘accessible’ or ‘available’ emissions factors: 

  • Accessible or Available: publicly available, free to use, and from a credible source 
  • Organisations are not required to use proprietary or paid emission factor databases
  • This balances accuracy improvements with feasibility for all organisation sizes

Load profiles can be used to approximate hourly consumption from annual or monthly data, enabling use of more granular emission factors even when detailed metering isn't available.

 

Impact 

Outstanding Questions 

This should drive greater consideration by organisations of the location and time of their demand. When combined with SBTi’s new requirements to set both location and market based emissions targets, this should encourage more consideration for choosing locations with higher renewables penetration (e.g. California, Spain) and shifting demand where possible to times of higher renewable generation. 

This will primarily affect developed markets and grids where more granular emissions data is available since markets without hourly data will remain on monthly or annual emissions factors.

With growing interconnection across neighboring markets, it is unclear how the hierarchy will apply for imported power, although it will likely just be covered as part of the grid emissions factor. 

It is also unclear how this will affect battery assets, namely how battery export to the grid will be treated, i.e. will this contribute to decarbonising a Scope 2 position and eligible for certificates, or is this to be captured by the consequential method. 

Market-based

Moving to hourly reporting

 

Aim 
Aligning contractual instruments (i.e. Energy Attribute Certificates) with electricity consumption on an hourly basis to more accurately reflect the emissions intensity of the grid mix consumed by companies

Application 
Feasibility 

All contractual instruments used in the market-based method must be matched on an hourly basis, except in certain exemption cases. 

 

Exemption thresholds: smaller organisations (threshold to be determined via consultation) may be exempt from hourly matching requirements 

 

Default exemption conditions being tested:  

  1. Companies with annual consumption up to [X] GWh/year in a deliverable market boundary may use monthly or annual accounting intervals; Aim is to focus hourly reporting towards large energy users over smaller companies

  2. Thresholds based on company size (potentially using SBTi company categorisation), i.e. categorised as a SME 
Load profiles: Organisations without hourly data can use pre-determined ‘load profiles’ to approximate hourly consumption from monthly/annual figures 
  • These are standardised hourly curves showing how electricity demand typically rises and falls throughout the year, based on facility type (e.g. retail business, data center, hospital) 
  • Hierarchy of profiles: facility-specific load profiles, market-boundary load profiles scaled by utility/customer class profile, time-of-use averages, flat average across all hours
 

Impact 
Outstanding Questions 
Potential major impact on EAC markets, prices and company willingness to pay (if moving to an hourly certificate standard): 
  • An hourly EAC market, in theory, would see certificate prices most expensive in periods of low renewable generation (grid connected and BtM) due to supply scarcity and high demand if corporates maintain their 100% renewable targets 
  • In this case, hourly certificate prices would likely mirror wholesale power prices (low in high renewable hours, low demand and high in low renewable, high demand hours) 
  • However, it is challenging to predict the impact on EAC prices as company appetite for certificates may change, i.e. will maintain commitments to zero Scope 2 emissions and therefore keep demand and prices high during peak periods, or will companies settle for increased scope 2 emissions, therefore reducing peak price periods 
  • This could also introduce periods of strategic EAC purchasing; if companies buy EACs when they are inexpensive, residual emissions in those periods will be low, meaning there may be more benefit to buy EACs when they are expensive as residual emissions then will be much higher 
Using load profiles may limit the incentive for companies to invest in DSR / batteries unless they have hourly data 
Unclear how GHGP will calculate hourly matching; CFE approach, or potentially an hourly matched EAC standard. 
 
Also no guidance yet on which technologies will be considered ‘renewable’ or zero-emission and eligible for EACs (i.e. nuclear and Energy from Waste) 

 

Standard Supply Services

 

Aim 

Aims to prevent double counting and provide global rules for how to account for electricity from publicly funded, mandated or shared resources – i.e. potentially those from Contract for Difference (CfD) support schemes, Renewable Portfolio Standards (RPS), Clean Energy Standards (CES), stae-level nuclear-support policies (United States), or Feed-in Tariff (FIT) mechanisms 

Application 

Feasibility 

Each reporting entity may account for its fair, proportional share of electricity from SSS resources  

That portion shall not be transferred or used to substantiate claims by another reporting entity  

Companies can claim only their pro-rata share of SSS resources; any unclaimed SSS contractual instruments are ineligible for use by other reporting entities

Applies to: 

  • Government-mandated clean energy procurement,  
  • Publicly owned facilities, or  
  • Generation subject to regulated cost recovery from a supplier

Impact 

Outstanding Questions 

Potential major impact for markets with high penetration of SSS resources, removing a large supply of EACs potentially causing prices to significantly rise (i.e. as transpired when the UK left the EU GoO market and removed GoOs from circulation in the UK). This may also remove an additional revenue stream for SSS generators.

It is unclear what markets will fall under SSS, and the impact that may have on renewable procurement strategies and EAC prices. 

It is also unclear how this will be accounted for, i.e. an equivalent, SSS EAC, or managed through a central database of SSS as a share of total generation, or another mechanism. 

 

Mandating Residual Mix emission factors

 

Aim 

Aims to prevent double counting in the case where one company retires EACs and another uses grid-average factors instead of residual mix (the same clean generation is counted twice). 

Application 

Feasibility 

 

 Eliminate grid-average factors as fallback: where no residual mix is available, companies must use fossil-only rates (gas, oil, or coal emission factors). 
 

For consumption not matched with SSS or voluntary certificates, use a residual mix factor that explicitly excludes all claimed and SSS contractual instruments.

 

 
 

This will increase pressure on markets to report residual emissions (else their scope 2 emissions will significantly increase). 

 

 

Impact 

This will impact companies using grid-average factors and increase market-based emissions.

 

Legacy clause

 

Aim 

Recognise existing long-term contracts entered in good faith and prevent any unfair disadvantage to early adopters.

Application 

Feasibility 

Design elements under consultation: 

  • Eligibility: Which instrument types qualify (PPAs, green tariffs, unbundled certificates, etc.) and any minimum original term 
  • Duration: Time limit after which updated Scope 2 Quality Criteria apply 
  • Allocation rules: Prevent legacy instruments being used strategically to avoid challenging hours 
  • Disclosure: Identify portion of consumption covered, affected periods, and phase-out timeline 
  • Potential cut-off dates: Contract signed prior to consultation publication date or prior to final standard publication date 

Potential alignment with other global standards asset life requirements: 

  1. SBTi Corporate Net Zero Standard: proposed change for EACs to be from generation assets commissioned or re-powered in the past ten years, with a progressive tightening to five years by 2035 
  1. RE100: Companies must buy renewable power from plants build or recommissioned less than 15 years ago (with 15% of renewable procurement exempt from this requirement)

 

Impact 

Outstanding Questions 

Highly dependent on the final clause

A broad clause will ensure the majority of long-term contracts and investments made to date have merit under the new standards.

 

A restrictive clause will be challenging and companies may need to consider renegotiating contracts so they apply to new standards.
 

It is unclear how the GHGP will apply grandfathering, and which investment (i.e. PPAs) will apply.

Deliverability requirements

 

Aim 

Ensuring energy certificates match electricity that can actually reach the consuming facility.

Application 

Feasibility 

All contractual instruments must be sourced from the same deliverable market boundary in which the reporting entity's electricity-consuming operations are located.

 

Market boundary: electricity from a generator could plausibly be part of the mix serving the reporting entity through an electrically connected grid.
Regional flexibility: In some countries, national borders will still approximate the deliverable boundary; in others with different grid operations, boundaries may differ from national borders.

 

Likely applies to the US, with multiple grid zones; i.e. day time RECs from Texas no longer valid for night-time consumption in California.

 

Impact 

Outstanding Questions 

Potential major impact on cross-border certificates (i.e. International Renewable Energy Certificates).

There may also be large regional swings in EAC prices (as when the UK left the EU GoO market), more pronounced in markets with lower renewable penetration.
More information is needed on application of market boundaries and which certificate programs this impact (e.g. I-RECS, US RECs, EU GOOS etc).

Consequential accounting

Consequential method

 

Aim 

Recognise the benefits of global / system-wide additional renewable deployment; i.e. investing in renewables where it has the most impact on lowering grid emissions.

Application 

Feasibility 

Elements under consultation: 

  • Additionality definition 
  • Marginal emissions definition 
  • How build Vs operate marginal emissions are accounted for
  • Build MERs: accounts for the level of infrastructure build-out required (or not required) from deploying a renewable asset (i.e. firm renewable power will displace fossil-fuels / thermal generation assets, reducing system wide emissions) 

VPPAs (and other procurements not time-matched or deliverable to the load) will likely fall under consequential accounting. 
Hourly marginal emissions rate data is required to calculate ‘avoided’ emissions, currently only provided by Watt Time, and no provider accredited. 

 

Proposing that the best approach to calculate MERs is to report both operating (OMERs) and build (BMERs). Several existing methods for calculating both are under consideration: 

  1. OMER methods: Security constrained economic dispatch (locational and fule-on-the-margin), scenario modelling, heat-rate (local marginal price data), statistical models, capacity-factor data or difference-based (change in system emissions across periods)
  2. BMER methods: recent capacity addition data (and weighted average emission rate), IEA policy scenarios, capacity expansion modelling or average emission factors (location-based method)

Impact 

Outstanding Questions 

We expect this will be a voluntary metric and most applicable to those building generating assets to recognise the marginal additional decarbonisation delivered and incentivise renewables development in higher-emissions grids.
Cited BMER methodologies do not recognise system-value contributions such as flexibility, renewable-integration support or grid services. For technologies like batteries and biofuels, which can enable fossil units to turn off and support system reliability in high-renewables systems, it is uncertain whether these effects should be reflected in long-term structural impact accounting. 

Consequential consultation

The consequential-method is reviewed in more detail in a separate consultation, exploring options for an avoided-emissions method that estimates the system-wide effects of clean-energy procurement and investment, separate to corporate inventories. This method will sit outside Scope 1, 2 and 3 accounting, and we expect it will be most relevant for companies deploying renewable assets who want to report this impact.

Specific topics considered are: 

  1. Formula for quantifying the emissions impact from electricity projects
  2. The treatment of additionality
  3. Marginal Emissions Rate methodologies
  4. Build vs Operate margin weighting  

What does this mean for energy markets? 

Many corporates had previously met their emission reduction goals by purchasing EACs, unbundled from the delivery of power (i.e. annual purchases to fulfil annual consumption volume). However, hourly accounting brings an end to the unbundled certificate market we know today. 

It is not clear how the GHGP plans to implement hourly accounting and there are few examples of this in practice, notably the UK’s Low Carbon Hydrogen Agreement, and the EU’s Green Hydrogen Standard. One possible method is to introduce an hourly certificate market, with certificates purchased and cancelled as they are today, but on an hourly granularity. 

While it’s impossible to predict the price impact on certificates, which had typically enjoyed fairly low prices (below £1/MWh for GB REGOs and below €1/MWh EU GoOs), an hourly certificate market could largely follow the hourly power price. This would see certificates most expensive in periods of low renewable generation (both grid connected and behind the metre) due to supply scarcity and likely high demand if companies maintain their 100% renewable targets. Equally, certificate prices would be lower in high renewable, low power price hours, as illustrated by the chart below. 

 

 

What does this mean for me?

Each week we will look at the impact for different market players. Coming next: Battery owners and operators

 

 

What are the different scopes and categories of GHG emissions?

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Hannah Simmonds

Expert in Corporate Decarbonisation

Contact Hannah

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