What are the proposed Scope 2 revisions?
The GHG Protocol released its summary of feedback from the public consultation on the proposed Scope 2 revisions on 29th July 2026. The consultation attracted nearly 1,100 participants across 56 countries, providing a broad range of perspectives on the proposed changes to market-based Scope 2 reporting.
Two of the most significant proposals under review were the introduction of hourly matching and deliverability requirements. Hourly matching would require electricity consumption to be matched with renewable electricity generation on an hourly basis, while deliverability would require EACs to originate from a location where the electricity could plausibly be delivered to the reporting organisation’s load.
While both proposals received significant support for improving the integrity and credibility of Scope 2 reporting, they also generated considerable concern around cost, feasibility, market participation and the availability of supporting infrastructure.
NUS has reviewed the feedback received on both the proposed hourly matching and deliverability requirements, including the key arguments supporting and opposing these changes. The review also considers the proposed legacy clause, which has become an important consideration for companies assessing the potential impact of the revisions on their existing and future energy procurement strategies.
What was the support for hourly matching?
Respondents supporting hourly matching generally viewed the proposed requirement as necessary to strengthen the integrity, credibility and accuracy of Scope 2 reporting by more closely aligning reported electricity consumption with the timing of renewable electricity generation. Many highlighted the “solar power at night” example as demonstrating the limitations of annual matching, where renewable generation can be matched against electricity consumption regardless of when the generation occurs, potentially increasing greenwashing concerns.
Hourly matching was also considered to improve the decision-usefulness, comparability and verifiability of market-based reporting by providing greater visibility of grid conditions and enabling organisations to make more informed decisions regarding electricity procurement, demand management and energy storage.
Respondents further noted that more granular matching could create stronger market signals for technologies and behaviours that support deeper grid decarbonisation, including clean firm power, long-duration energy storage and demand flexibility.
While some respondents recognised that hourly market infrastructure and tracking systems are not yet available in all regions, others highlighted that the increased demand for hourly matching could contribute to the development of hourly EAC systems. Existing hourly EAC initiatives in markets such as Australia, Taiwan and the UK were highlighted as evidence that market capabilities are evolving.
Finally, respondents noted that the proposed requirement is increasingly aligned with developing regulatory frameworks, including the EU Carbon Border Adjustment Mechanism (CBAM), which incorporate more granular approaches to electricity sourcing.
What were the concerns for hourly matching?
Respondents expressing concerns about hourly matching generally focused on the increased reporting burden, costs, infrastructure requirements and potential impacts on voluntary electricity procurement markets. Many noted that implementation would require significant changes to internal data management, with additional costs associated with staff, software, consultancy and potentially higher-priced hourly EACs.
These concerns are particularly relevant in markets where supporting infrastructure is not yet sufficiently developed. Respondents highlighted that interval electricity data, hourly certificate systems and eligible supply may be limited across markets outside of North America and Europe. Some respondents further suggested that mandatory hourly matching could reduce participation in voluntary procurement markets by increasing complexity, creating price premiums and reducing liquidity, with potential implications for long-term renewable procurement such as PPAs by increasing the complexity for the off-takers.
Others questioned whether the additional temporal granularity would materially improve the accuracy or representativeness of market-based Scope 2 reporting, noting that electricity cannot be physically traced through interconnected grids and that contractual instruments do not necessarily maintain a direct physical connection between consumption and emissions.
Finally, some respondents noted that hourly matching alone may not deliver the intended system-wide decarbonisation outcomes, highlighting the absence of an incrementality requirement alongside hourly matching and deliverability as a potential limitation of the proposed approach.
What was the support for deliverability?
Respondents supporting the proposed deliverability requirements generally viewed them as necessary to strengthen the accuracy, credibility and transparency of Scope 2 market-based claims by ensuring that contractual instruments originate from electricity systems that can plausibly serve the reporting organisation’s load. Many noted that certificates from physically disconnected regions can weaken the relationship between reported claims and the electricity system serving consumption, while defining geographic boundaries could better align market-based accounting with the physical realities of electricity supply.
Respondents also suggested that deliverability could improve procurement incentives by directing investment towards regions where additional clean energy supply and flexibility are needed, rather than concentrating procurement in areas where renewable certificates are most abundant and inexpensive, such as Norway certificates being purchased for Europe and Texas RECs being purchased for US consumption.
Some further noted that clearer deliverability requirements could encourage investment in interregional transmission, if the demonstration of physical connectivity becomes required for cross-boundary claims, and support more targeted grid decarbonisation.
Respondents also highlighted potential benefits for the credibility, comparability and legal defensibility of corporate climate claims, suggesting that clear geographic criteria could reduce ambiguity during assurance and increase confidence among investors and regulators.
Finally, some respondents noted that generation and consumption locations are already captured within existing registries and tracking systems, indicating that defined market boundaries could be implemented using existing data and infrastructure while providing more verifiable criteria for reporting.
What were the concerns for deliverability?
Respondents expressing concerns about the proposed deliverability requirements generally focused on the potential impact on corporate procurement scale, market participation and the feasibility of applying geographic constraints across diverse electricity markets. Many noted that narrower boundaries could fragment aggregated corporate demand, making it more difficult for organisations with dispersed operations to support large-scale PPAs and potentially shifting procurement towards short-term, unbundled certificates.
Respondents also raised concerns that smaller market boundaries could cause reduced market liquidity, increased price volatility and additional administrative requirements which would therefore in effect increase procurement costs and discourage voluntary renewable energy investment.
Many respondents argued that deliverability requirements could also limit organisations’ ability to direct investment towards higher-emitting grids where renewable energy projects may deliver greater marginal emissions reductions, with some respondents highlighting potential implications for energy access and investment in developing economies. Others questioned the conceptual basis for applying physical delivery requirements to a contractual market-based accounting method, noting that electricity cannot be physically traced between individual generators and consumers on interconnected grids and that robust certificate tracking and prevention of double counting may provide sufficient safeguards.
Finally, some respondents highlighted regional feasibility concerns, particularly where renewable supply or supporting tracking infrastructure is limited/not mature and noted that the proposed boundaries may not accurately reflect the physical characteristics of interconnected electricity systems. Some suggested that deliverability boundaries should be based on grid and transmission characteristics, with wider regions potentially providing a more appropriate representation of the physical electricity markets.
What was the support for a Legacy Clause?
Respondents supporting a legacy clause generally viewed it as necessary to maintain market trust, protect early adopters and provide certainty for organisations that entered into long-term contracts under the rules in place at the time. Many noted that retroactively applying new requirements could undermine existing commitments and discourage future investment in long-term emissions reduction projects.
Respondents also highlighted the potential financial impact of excluding existing contracts from Scope 2 reporting, noting that long-term PPAs can involve significant sunk costs and are an important component of renewable energy project financing. Some further noted that renegotiating existing agreements to meet new requirements could be impractical due to counterparty consent, legal costs and potential triggering of termination clauses. Respondents that are users of climate-related financial risk disclosure programs cited that changes to the eligibility of legacy contracts could have financial reporting risks by altering the economic value of pre-existing agreements.
Finally, respondents indicated that uncertainty surrounding the proposed revisions is causing organisations to delay new renewable energy procurement, with many viewing a legacy clause as particularly important before the full standard is finalised.
What are the concerns with a Legacy Clause?
Respondents expressing concerns about a legacy clause focused on its potential to reduce comparability, credibility and the pace of transition towards higher-quality electricity procurement instruments. Many noted that allowing existing contracts to operate under different requirements could create a dual-track reporting system, making comparisons between organisations less reliable and more complex for auditors, assurance providers and disclosure frameworks such as ISSB, CSRD, CDP and RE100.
Respondents also questioned whether legacy exemptions are consistent with the purpose of the market-based method, suggesting that contracts which do not meet updated criteria could produce reported emissions values that are less representative of physical grid impacts and increase exposure to greenwashing concerns. Some further highlighted that different requirements for existing and new market participants could create competitive disadvantages for organisations entering the market after the revisions are implemented.
Finally, respondents expressed concern that a legacy clause could reduce the incentive for organisations to transition towards hourly-matched and deliverable instruments, and therefore slow market progress.
What does this mean for companies?
The proposed Scope 2 revisions could have significant implications for how companies approach renewable electricity procurement and the reporting of Scope 2 market-based emissions. While the final requirements have not yet been confirmed, companies should begin assessing how hourly matching and deliverability could affect their existing procurement strategies, particularly where electricity consumption is spread across multiple markets or where long-term PPAs and EAC contracts are already in place.
Companies should also consider the potential impact of the proposed changes on future procurement decisions. Moving towards more granular and geographically aligned electricity procurement may increase the complexity and cost of sourcing EACs, while potentially changing the relative attractiveness of PPAs, unbundled certificates and other procurement mechanisms. Organisations should therefore assess their current electricity procurement portfolio against the proposed requirements and identify where existing contracts may be affected.
The proposed legacy clause may provide some protection for existing contracts if the new requirements become mandatory, but companies should not rely solely on this provision when developing long-term procurement strategies. As the GHG Protocol continues to refine the proposals, organisations should monitor developments and consider how future procurement commitments can remain aligned with evolving Scope 2 reporting requirements.
How NUS Can Help
If you wish to speak further about the GHG Protocol Scope 2 Revision or on how these changes may affect your organisation, NUS can support, please contact us: contact@nusconsulting.co.uk.