This article is the third in a series developed by Three Pillars Consulting on product-level emissions reporting within the petrochemical sector and co-published with GPCA. The first article introduced the distinction between corporate-level and product-level GHG reporting. The second article explored how the carbon intensity of the electricity grid influences Product Carbon Footprints (PCFs) for GCC producers and their exposure to the EU Carbon Border Adjustment Mechanism (CBAM). This third article examines how producers can take an active role in managing the electricity-related component of their PCF through contractual mechanisms such as International Renewable Energy Certificates (I-RECs), how this can strengthen export competitiveness for GCC petrochemical and chemical producers, and what this means under evolving requirements across GHG Protocol, ISO 14067, Science Based Targets initiative (SBTi), and CBAM.
Recap of Articles 1 and 2: From grid intensity to active emissions management
The first two articles in this series established that emissions disclosures are becoming more predominately focused on product carbon footprinting (PCF), a shift from primarily corporate-level accounting. A key factor in calculating PCF values is electricity consumption and its corresponding Scope 2 emissions (and Scope 3 Category 3 emissions as well). Thus, the location of a manufacturing plant, including petrochemical and chemical facilities, can materially influence the PCF. This is because the location will dictate both the sources of grid electricity available to the manufacturing plant for sourcing electricity as well as the contractual mechanisms available to the manufacturing plant for making legitimate and verifiable redemption claims for such electricity.
As Article 2 discusses, GCC producers operate in moderately carbon-intensive grid network, with grid emission factors (GEFs) currently ranging from approximately 302 to 737 g CO2e / kWh across the six GCC countries[1]. Moreover, and as will be discussed further in this article, petrochemical and chemical producers have different contractual mechanisms (e.g. I-RECs and PPAs) available to them – in addition to the different grid emissions intensities – based on their location (i.e. country of production) and corresponding regulatory environment, which in turn could impact how those producers communicate and disclose their product-level GHG intensities, CBAM liabilities, and ESG ratings.
While the previous article also highlighted that grid decarbonization (i.e. through deployment of utility-scale renewable energy projects) is expected to reduce location-based grid average emissions factors (GEFs) significantly over the coming decades, it did not explain the opportunities and limitations existing today in using contractual mechanisms for market-based Scope 2 accounting and decarbonization target setting.
[1] Source: IEA Emissions Factors Database (2024); Climate Transparency Report; Ember Global Electricity Review 2024.
*Oman’s data supplied directly from Three Pillars Consulting and primary data it has collected from within the country.
Note: Grid emission factors vary by year and source; figures represent approximate ranges from available data.
Two methods, one electricity supply: Location-based and market-based accounting
The GHG Protocol Scope 2 Guidance (2015) established two distinct methods for reporting indirect emissions from purchased electricity:
- Location-based method: uses the average grid emissions intensity of the country or region in which electricity is consumed. For most GCC countries, this means applying a fossil-fuel-dominated grid average factor of approximately 302 to 737 g CO2e / kWh.
- Market-based method: uses the emissions factor derived from the company’s contractual electricity instruments (described further below). Where a company has purchased and retired an energy attribute certificate (EAC), for example, sourced from a renewable project, it may use a zero or near-zero emission factor for the electricity covered by those EACs.
A key element of market-based accounting is the Residual Mix. When an EAC is redeemed, the corresponding renewable generation attribute is assigned to that beneficiary. The un-redeemed electricity in the grid defines the Residual Mix. And the Residual Mix Emissions Factors (REF), thus represents the emissions intensity of the grid after factoring out the redeemed renewable energy. The REF thus reflects a grid with less relative renewable energy compared to the GEF and thus generally expected to be higher (i.e. more carbon intensive electricity ratio). Companies that do not redeem EACs are, in practice, implicitly consuming from the residual mix.
Extending the logic to Scope 3: Upstream PCFs and buyer emissions
The implications of EAC redemptions do not stop at the producer. For a downstream buyer (i.e. a polymer converter, a fertilizer distributor, or an industrial gas customer) the PCF reported by their GCC supplier flows directly into their own Scope 3, Category 1 (Purchased Goods and Services) emissions. Table 3 illustrates this: if a supplier reduces the Scope 2 component of its PCF by retiring I-RECs, the buyer’s Scope 3 Category 1 calculation changes proportionally, without any change at the buyer’s facility.
This dynamic is becoming commercially significant. European importers and buyers increasingly request or mandate PCF data from their supply chains, and some procurement frameworks, particularly in the construction sector (via EPDs) and the automotive and electronics industries, are beginning to set maximum PCF thresholds for preferred-supplier status. A GCC producer that can demonstrate a lower PCF through the use of credible contractual mechanisms is not merely scoring better on an ESG questionnaire; it is demonstrating a potential competitive advantage that may support preferred-supplier status and / or contract retentions and extensions. In the ammonia and fertilizer space specifically, where the EU’s Carbon Border Adjustment Mechanism (CBAM) already applies, the financial stakes are direct and quantifiable.
CBAM: A story of contractual mechanisms
EACs, such as I-RECs, are legitimate and commonly utilized contractual mechanisms for Scope 2 accounting and reporting under global standards, methods, and disclosure programs. This is most prominently outlined in the GHG Protocol’s Scope 2 Guidance (2015), which places EACs (such as Guarantees of Origin, Renewable Energy Certificates, I-RECs, and other similarly unbundled or bundled EACs) at the top of the hierarchy for the market-based approach to Scope 2 accounting (Table 4).
This is reinforced subsequently by other carbon accounting and life-cycle assessment standards such as those for Environmental Product Declarations (EPDs) and PCFs. For example, ISO 14067:2018 (“Greenhouse gases – Carbon footprint of products – Requirements and guidelines for quantification”) states in Section 6.4.9.4.2 that when electricity is sourced from the grid, then supplier-specific contractual instruments shall be used for calculating those emissions. The standard goes on to say that when supplier specific electricity is not available alongside a contractual instrument, then the residual emissions factor shall be used, and if no electricity tracking system is in place, then the grid average emissions factor shall be used.[1]
[1] The ISO 14067:2018 standard states explicitly that “the relevant grid shall reflect the electricity consumption of the related region, excluding any previously claimed attributed electricity”. The standard goes on to say that “in case no electricity tracking system is in place, the selected grid shall reflect the electricity consumption of the region”.
Moreover, the GHG Protocol’s Product Life Cycle Accounting and Reporting Standard (2011) states in Box 8.3 that the preference for selecting electricity emissions factors is to use a “supplier-specific emissions factor [if] these emissions are excluded from the regional emissions factor” (i.e. so that a legitimate REF can be calculated), otherwise “companies should use “a regional average emissions factor for electricity”. Therefore, this puts the priority in favor of using EACs where a legitimate tracking system (i.e. registry) is in place and where REF values are readily available for all market players. Otherwise, companies are to use GEF values for their Scope 2 reporting.
Furthermore, under Section 4.7.2 (i.e. “Electricity Modeling) of the EPD Product Category Rule (PCR) for Construction Products (PCR 2019:14, Version 2.0.1), explicitly states that “market-based modeling shall be used” for calculating emissions from grid electricity and that “contractual instruments (e.g. Guarantees of Origin) may be used to demonstrate the use of a specific electricity mix). PCR 2019:14 does not specify the type of contractual instrument that should be used, but in Section 4.7.2.3 the standard states that the contractual instrument shall ensure “reliability, traceability, and the avoidance of double counting”.
However, under the EU’s CBAM Regulation EU 2023/956, a company that wants to use a supplier-specific emissions factor for electricity-based emissions (i.e. what is referred to by CBAM as “actual indirect embedded emissions) either needs to demonstrate a direct link between the electricity producer and electricity consumer or ‘demonstrate’ a power purchase agreement (PPA). Accordingly, the EU 2023/956, one of the key stipulations is defining the PPA as a contract between the electricity consumer and the electricity producer and whereby the contract is for the physical delivery of electricity. This inherently puts the burden-of-proof onto unbundled EACs to demonstrate whether such an EAC would constitute a PPA. The current interpretation of the EU regulations is that unbundled EACs do not comply with the regulation.
Thus, companies can avail EACs such as GOs, RECs, and I-RECs for fulfilling nearly all major global carbon reporting and disclosure programs, such as the GHG Protocol, ISO 14067 as well as for obtaining certifications such as EPDs or setting their net-zero targets under SBTi. However, companies are currently not able to avail the redemption of unbundled EACs under their CBAM reporting and CBAM declarations. Therefore, continued dialogue between industry stakeholders, standard setting bodies, and regulators could help harmonize and enhance greater consistency for international GHG related disclosures.
Currently, Market-Based Scope 2 Accounting and the use (and interpretation) of contractual mechanisms are under evaluation as a part of a larger revision of the GHG Protocol’s Corporate Standard, the joint GHG Protocol & ISO Product-Level Standard, as well as SBTi’s continued revision of their Net Zero Standard. In most cases, it is assumed that there will be continued use of contractual mechanisms for Market-Based Scope 2 Accounting, however with tighter controls and requirements around temporal correlation, geographic correlation, and other concepts like additionality[1]. Therefore, GCC petrochemical and chemical producers, particularly those serving markets outside the EU, should consider using EACs for market-based Scope 2 accounting, EPDs, and PCFs, subject to the requirements of the relevant framework. Where available and qualifying, producers should additionally utilize PPAs to meet the methodology requirements of the EU’s CBAM.
For further information on the evolving discussions around Market-Based Scope 2 Accounting and contractual mechanisms, the reader is referred to the GHG Protocol’s Repository for their Standards Development and Governance and SBTi’s recent release of its Version 2.0 Standard for Corporate Net Zero.
References:
- [1] Source: IEA Emissions Factors Database (2024); Climate Transparency Report; Ember Global Electricity Review 2024.
- *Oman’s data supplied directly from Three Pillars Consulting and primary data it has collected from within the country.
- Note: Grid emission factors vary by year and source; figures represent approximate ranges from available data.
- [2] https://ghgprotocol.org/scope-2-guidance
- [3] The ISO 14067:2018 standard states explicitly that “the relevant grid shall reflect the electricity consumption of the related region, excluding any previously claimed attributed electricity”. The standard goes on to say that “in case no electricity tracking system is in place, the selected grid shall reflect the electricity consumption of the region”.
- [4] https://ghgprotocol.org/scope-2-guidance
- [5] https://ghgprotocol.org/standards-development-and-governance-repository
- [6] https://www.iso.org/standard/71206.html
- [7] https://ghgprotocol.org/product-standard
- [8] https://www.epdint.cn/wp-content/uploads/2026/04/PCR-2019-14-V2.0.1.pdf
- [9] https://standards.sciencebasedtargets.org/
- [10] https://taxation-customs.ec.europa.eu/carbon-border-adjustment-mechanism_en
- [11] To illustrate current language on this topic, PCR 2019:14 clarifies that the redemption of an EAC should be as close as possible to the certificate’s associated period of electricity production or in a corresponding timespan, and whereby the certificate represents electricity that is produced within the same country or market boundaries where consumption occurs (assuming interconnectivity).
