GHG Protocol Scope 2 Guidance — The Definitive Reference

Executive Summary

The GHG Protocol Scope 2 Guidance is, operationally, the most consequential document in the GHG Protocol suite for the typical reporting company. Almost every organisation purchases electricity; very few burn enough fuel to make Scope 1 dominate the inventory; Scope 3 is enormous in absolute terms but largely composed of estimates. Scope 2 sits in the middle — large enough to matter, accurate enough to defend, and tightly governed by a single rulebook that has shaped corporate energy procurement strategy worldwide since 2015.

The Guidance does three things. First, it defines what Scope 2 covers: emissions from purchased electricity, steam, heat, and cooling, consumed within the company’s chosen consolidation boundary. Second, it requires dual reporting — every company in a market with contractual instruments available must report Scope 2 using both the location-based method (grid-average factors) and the market-based method (contractual instruments). Third, it specifies the integrity infrastructure that makes contractual instruments credible: an eight-criterion quality test that every instrument must satisfy, and a five-tier hierarchy that orders which factor a company must apply when multiple factors are available.

As of May 2026, the 2015 Guidance remains the operative text, but a public consultation on a comprehensive revision is well underway. The Market-Based Accounting Technical Working Group is examining hourly matching, deliverability tightening, the U.S. residual mix gap, and the future of unbundled EAC eligibility. Companies designing their Scope 2 procurement strategy today should treat the 2015 Guidance as the floor and read the trajectory of the revision — and of the adjacent SBTi V2.0 and RE100 frameworks — as the ceiling.

What the Scope 2 Guidance Is

The Scope 2 Guidance is a formal amendment to the GHG Protocol Corporate Standard, not a standalone replacement of it. The Corporate Standard, first published in 2001 and revised in 2004, defined Scope 2 in principle and required its disclosure. The 2015 Scope 2 Guidance supplied the technical specification — exactly how to calculate and disclose Scope 2 emissions in a way that is comparable across companies, geographies, and procurement structures.

The amendment relationship matters. The Corporate Standard remains the governing document for the consolidation approach (operational control, financial control, equity share), the seven inventory principles (relevance, completeness, consistency, transparency, accuracy, plus the two governing principles), the base year and recalculation rules, and the gas coverage. The Scope 2 Guidance inherits all of these and adds a layer of technical specificity for one specific category of emissions. A company applying the Guidance is, by definition, applying the Corporate Standard underneath it — not choosing between them.

What the Guidance covers is also bounded. It governs the four types of purchased energy that produce Scope 2 emissions: electricity, steam, district heat, and district cooling. It does not cover on-site generation (which is Scope 1), self-generated electricity sold to the grid (which involves a Scope 1 reduction, not a Scope 2 calculation), or transmission and distribution losses on purchased electricity (which sit in Scope 3 Category 3). A clear understanding of what is and is not in scope is the single most important defence against the most common Scope 2 reporting errors.

Why the Guidance Exists

Before 2015, every company calculated purchased-electricity emissions differently. Some used national grid averages. Some used utility-specific factors. Some applied the emission rate of their renewable PPA contracts, treating the underlying electricity as zero-carbon. Some retired RECs and claimed an offsetting reduction without documenting whether the certificates met any quality threshold. Some did all of this in parallel, depending on which framework they were reporting to. The result was a patchwork: two companies with identical electricity consumption in identical markets could report wildly different Scope 2 numbers, with no shared technical specification an auditor or analyst could apply to test whether either was right.

The Guidance closed that gap. It made dual reporting mandatory, so the location-based number — the grid-average reality — is always disclosed alongside any market-based claim. It made the market-based method’s contractual instruments testable through the eight Quality Criteria. It ranked the available factors in a strict hierarchy, so a company faced with multiple legitimate options has a defined preference order rather than a discretionary choice. And it tied all of this to the Corporate Standard’s consolidation rules, so the Scope 2 boundary aligns with the rest of the inventory.

The Guidance has become the technical foundation that the entire corporate climate disclosure ecosystem depends on. The SBTi Corporate Net-Zero Standard uses it to measure Scope 2 reductions. CSRD ESRS E1 requires both location-based and market-based Scope 2 to be disclosed under E1-6. IFRS S2 references the GHG Protocol for emissions measurement, which means it references the Scope 2 Guidance for the Scope 2 line. The U.S. SEC’s climate disclosure rule, finalised in 2024, follows the same architecture. RE100 sits on top of the Guidance — RE100’s “100% renewable electricity” claim is operationalised through the same contractual-instrument framework the Guidance defines.

Publication History and the 2026 Revision Signal

The Scope 2 Guidance has been published once. Its incorporation into adjacent frameworks, and the live revision process, are where most of the version-tracking complexity lives.

Governance: WRI, WBCSD, and the Multi-Stakeholder Process

The GHG Protocol is co-published by the World Resources Institute (WRI) and the World Business Council for Sustainable Development (WBCSD). The two organisations jointly steward the suite of standards and guidance documents — the Corporate Standard, the Scope 2 Guidance, the Scope 3 Standard, the Project Protocol, the Product Standard, and the newer Land Sector and Removals Guidance — under the GHG Protocol initiative banner.

The development process is multi-stakeholder. Each document is developed through a structured cycle of working group meetings, public surveys, draft circulation, public consultation, and pilot testing before final publication. The 2015 Scope 2 Guidance ran through this cycle from 2010 to 2015, with extensive input from corporate buyers, registry operators, utilities, regulators, and assurance providers. The current 2026 revision is following the same pattern: Steering Committee oversight, a Market-Based Accounting Technical Working Group composed of subject-matter experts, public surveys to gather initial input, and staged public consultation as drafts mature.

This governance separation between standard-setter (the GHG Protocol initiative) and downstream verifiers (CDP, SBTi, assurance firms applying ISAE 3410) is a deliberate architectural choice. The Protocol writes the rules; the verifiers apply them; the assurance industry tests them in audit. The same separation exists in the SBTi (standard-setter) versus SBTi Services (validator) split, and in the RE100 Technical Advisory Group versus CDP reporting platform split. It is the foundation of the credibility of the entire ecosystem.

What Scope 2 Covers

Scope 2, as defined by the Guidance, is the emissions associated with the generation of purchased or acquired electricity, steam, heat, and cooling that is consumed within the reporting company’s consolidation boundary. The four energy types and the “purchased or acquired” trigger are both load-bearing.

The four energy types

• Electricity. The dominant Scope 2 category for almost every reporting company. Covered by both the location-based and market-based methods.
• Steam. Purchased process steam, typically supplied by a utility or industrial neighbour. The emission factor chain runs from the upstream fuel through the boiler efficiency to the delivered steam.
• District heat. Hot water or low-pressure steam supplied by a centralised heating system. Common in northern Europe, Scandinavia, parts of Russia and China, and increasingly in net-zero-aligned urban developments globally.
• District cooling. Chilled water supplied by a centralised cooling system. Common in dense urban centres in the Middle East, Singapore, Hong Kong, and increasingly in North American downtown cores.

“Purchased or acquired” — the trigger

Scope 2 attaches when a company purchases or acquires energy from a third party. On-site generation that the company itself operates and consumes — solar panels on its own rooftop, a co-generation plant inside its factory fence — is Scope 1, because the combustion or generation activity is inside the company’s operational boundary. The Scope 1 / Scope 2 boundary is the meter at the property line: energy crossing inwards from a third party is Scope 2; energy generated and consumed entirely inside the boundary is Scope 1.

Boundary alignment with the Corporate Standard

The consolidation approach — operational control, financial control, or equity share — is set at the company level under the Corporate Standard and applies uniformly to Scope 2. A company reporting under operational control includes Scope 2 from every facility where it has operational control, regardless of ownership. A company reporting under financial control includes Scope 2 from facilities consolidated in its financial statements. The choice cannot be different for Scope 2 than for Scope 1.

For a fuller treatment of the boundary, including the leased-asset rules, see the Scope 2 emissions glossary entry.

The Dual-Reporting Requirement

Dual reporting is the architectural innovation of the 2015 Guidance and the most-searched section of any reference page on the topic. The rule is simple in principle and consequential in practice: every company in a market where contractual instruments are available must report its Scope 2 emissions using both the location-based method and the market-based method, in parallel, for the same consumption.

Why both, not one

The two methods answer different questions. The location-based method asks: “What were the emissions of the electricity actually flowing through the wires this company drew on?” It is anchored to the physical grid in the geography of consumption. The market-based method asks: “What were the contractual emissions of the electricity this company purchased?” It is anchored to the legal instruments — supplier-specific factors, EACs, PPAs, default deliveries — that the company’s procurement decisions created.

Neither method is “more correct.” They are answering different questions, and a company’s stakeholders have legitimate reasons to want both. An investor assessing physical climate risk wants to know what grid the company is exposed to (location-based). A buyer assessing the company’s procurement strategy wants to know what contracts the company has signed (market-based). A regulator setting policy for grid decarbonisation wants both: the location-based number tells them where the load actually sits; the market-based number tells them how much voluntary procurement is shifting the dial.

When dual reporting does not apply

The Guidance is explicit that the market-based method applies wherever contractual instruments are available. In markets where no contractual instruments exist — no EAC system, no green tariff, no PPA market — the market-based method may not be applicable, and the company reports only the location-based number. As the global EAC infrastructure has matured, this exemption has narrowed: most large markets now have at least an I-REC or domestic equivalent available, so the threshold for a “no instruments available” claim is high.

For a side-by-side comparison of the two methods, see the Scope 2 location-based vs market-based comparison page. For the underlying methodology behind the GreenCalculus Scope 2 calculator, see Scope 2 electricity methodology and Scope 2 market-based methodology.

The Location-Based Method

The location-based method calculates Scope 2 emissions using the grid-average emission factor for the geography where the consumption occurs. The factor reflects the actual fuel mix of the grid — coal, gas, nuclear, hydro, wind, solar, and the rest — averaged across the period and the geographic area.

The factor hierarchy for location-based

The Guidance specifies a preference order when multiple grid factors are available for the same consumption point:

1. Sub-national grid factor where one is published. In the United States, EPA eGRID subregion factors are the standard reference. In some other countries, regional grid factors are published by the system operator.
2. National grid factor where no sub-national factor is published or where the consumption spans the national grid. The IEA, DEFRA (United Kingdom), Environment and Climate Change Canada, and equivalent national bodies publish these.
3. Cross-national or supranational factor as a last resort where no national factor is available — for example, a regional grid factor for a small island state with no published national factor.

Primary factor sources

The dominant published sources by region:

• IEA Emission Factors. National grid emission factors for almost every country, updated annually, used as the global default where domestic factors are not available. See the IEA Grid Emission Factors 2026 reference dataset.
• U.S. EPA eGRID. Sub-national grid factors for the U.S. NERC subregions, published every two to three years. The standard reference for U.S. consumption.
• UK DEFRA. National factors for the United Kingdom, updated annually. See the DEFRA emission factors reference dataset.
• European Environment Agency and AIB. National factors and the residual mix factors for the European single market.
• Climate Transparency / national inventories. Where IEA factors are stale, national inventory factors published for UNFCCC reporting can serve as the primary location-based reference.

For the term itself, see the Scope 2 location-based and electricity emission factor glossary entries.

The Market-Based Method

The market-based method calculates Scope 2 emissions using the contractual instruments that govern the emissions rate of the electricity the company has purchased. Where the location-based method asks what the grid average was, the market-based method asks what the company specifically procured — the supplier-specific rate, the EAC-bundled rate, the PPA-supplied rate — and applies that rate to the consumption.

The market-based method is the framework that makes voluntary renewable procurement matter for inventory accounting. If a company in a coal-heavy grid signs a PPA with a new wind farm, the location-based number does not move (the grid is still coal-heavy), but the market-based number falls to reflect the wind procurement. The Scope 2 Guidance is what makes this distinction technically auditable, and what makes “100% renewable electricity” claims under RE100 reconcile to the inventory.

For the term itself, see the Scope 2 market-based glossary entry.

The integrity of the market-based method depends on two structures specified in the Guidance: the eight Quality Criteria (which determine whether a contractual instrument is eligible to enter the calculation at all) and the five-tier emission factor hierarchy (which determines which factor a company must apply when multiple are available). Both are addressed in detail below.

The Five-Tier Emission Factor Hierarchy

The Guidance specifies a strict preference order for which emission factor a company must apply in market-based accounting. The hierarchy resolves the practical question: when multiple factors are technically available — a supplier-specific rate, an EAC-backed rate, a residual mix factor, a grid average — which one does the company use? The answer is the highest-tier factor that is available and that satisfies the eight Quality Criteria.

The hierarchy is operationally inseparable from the eight Quality Criteria. A factor that fails any of the eight criteria drops down the hierarchy: an EAC that is not retired in the same market as consumption is not eligible at Tier 1 and must be re-evaluated at the highest tier where it does qualify, often Tier 4 or Tier 5.

The Eight Scope 2 Quality Criteria

The Quality Criteria are the integrity backbone of the market-based method. Every contractual instrument used to apply a Tier 1 factor — every EAC, every PPA-bundled certificate, every disclosed green tariff — must satisfy all eight criteria. An instrument that fails any one criterion is not eligible for Tier 1 use and is reassessed at the highest tier where it does qualify. This is the single most-checked section of any market-based Scope 2 inventory under assurance.

The criteria are cumulative. An instrument satisfying seven of the eight is not Tier 1 eligible — it must satisfy all eight. The most common failure modes in practice are criterion 6 (out-of-market sourcing), criterion 4 (claimed but not retired in the registry), and criterion 5 (vintage outside the reasonable window). The 2027 CDP cycle’s hardening of cancellation evidence requirements for RE100 claims is a direct response to widespread criterion-4 failures in PPA-based reporting.

Contractual Instruments — The Five Types

The Guidance recognises five categories of contractual instrument for the market-based method. Each is operationally distinct, each has its own audit trail, and each interacts with the Quality Criteria differently.

1. Energy attribute certificates (EACs)

The dominant instrument globally. EACs are standardised electronic certificates representing the environmental attributes of one MWh of renewable generation. The major regional types are Guarantees of Origin (GOs) in the AIB-member European single market, REGOs in the United Kingdom, RECs in the United States, LGCs in Australia, NFCs and J-Credits in Japan, RECs in India under CERC, and I-RECs in markets without an established domestic system. The Energy Attribute Certificates glossary entry covers the registry mechanics. EACs can be procured bundled (with the underlying electricity) or unbundled (separately). Both pathways are eligible under the market-based method provided the eight Quality Criteria are satisfied.

2. Power Purchase Agreements (PPAs)

Direct contracts between a corporate buyer and a renewable generator. Two structural types: physical PPAs, where the buyer takes physical delivery of the electricity, and virtual or financial PPAs, where the buyer contracts for the financial settlement (a contract-for-difference structure) without physical delivery. Both types can support market-based claims, and both must include explicit EAC bundling — the contract must clearly state that the renewable attribute certificates are conveyed to the buyer and retired on their behalf. PPAs without explicit EAC retirement provisions are a major audit risk under criterion 4 and will be excluded from RE100 claims from the 2027 CDP cycle.

3. Supplier-specific contracts and green tariffs

Utility-supplied electricity products with disclosed renewable content. A “green tariff” varies enormously in quality: at one end, a utility product backed by retired EACs from disclosed projects (Tier 1 eligible); at the other, a marketing label with no underlying instrument retirement (not eligible for any tier above Tier 5). The Quality Criteria are the only test that distinguishes the two — a green tariff is Tier 1 eligible only if the underlying instruments satisfy all eight criteria.

4. Self-generation with retained attributes

Where a company generates electricity on-site (rooftop solar, on-site wind, behind-the-meter co-generation) and retains the environmental attributes — that is, does not sell the associated SRECs or equivalents — the underlying generation can be claimed in market-based accounting. The technical condition is attribute retention: in markets with active SREC programmes, on-site solar projects often monetise the certificates separately, in which case the underlying generation does not count toward the company’s market-based claim. On-site generation that is consumed on-site is also Scope 1 generation, not Scope 2 — the market-based interaction arises only when the on-site generation displaces purchased electricity.

5. Direct contracts and bilateral arrangements

Direct bilateral agreements with disclosed source — for example, a long-term offtake contract with a specific generator where the EAC component is documented in the contract. These arrangements are most common in markets without a deep PPA market or where bilateral structures are favoured for contractual or tax reasons. The Quality Criteria apply identically.

For the cross-cutting interaction with the broader corporate renewable claim, see the RE100 Technical Criteria reference page.

The Residual Mix and T&D Losses

Two related concepts often misunderstood as part of Scope 2 sit just outside or alongside it: the residual mix (the market-based fallback for buyers who have not procured attributes) and transmission and distribution losses (a Scope 3 category often confused with Scope 2). Treating both together clarifies the boundary.

The residual mix

The residual mix is the emissions intensity of grid electricity after subtracting the share already claimed by EAC retirements. Conceptually: when a company in market A buys and retires an EAC, the underlying renewable MWh is “removed” from the pool that everyone else implicitly draws on. The residual mix factor reflects this subtraction — it is the location-based factor adjusted upward to account for the renewable shares already allocated to other buyers.

The residual mix is the Tier 4 fallback in the emission factor hierarchy. A company in a market with an EAC system, but which has not retired EACs of its own, applies the residual mix factor as its market-based number. The mathematical relationship is direct: as more EACs are retired in a market, the residual mix gets dirtier, because the cleanest MWh have already been claimed.

Two practical complications. First, the European residual mix is centrally calculated and published by the Association of Issuing Bodies (AIB) on an annual basis, with national breakdowns. This makes Tier 4 application straightforward in AIB markets. Second, the United States has no nationally calculated residual mix — eGRID is a generation-based location average and is not adjusted for voluntary REC retirements. This is one of the most operationally consequential gaps in the global Scope 2 system, and one of the issues the 2026 revision is examining directly.

T&D losses — Scope 3, not Scope 2

Transmission and distribution losses are the electricity lost as heat in the grid between the generation point and the consumption point. Globally, T&D losses average around 8% of gross generation, with significant national variation. Under the GHG Protocol, the emissions associated with T&D losses are reported in Scope 3 Category 3 (“Fuel- and energy-related activities not included in Scope 1 or Scope 2”), specifically Category 3b. They are not part of Scope 2.

The double-counting risk is real and surfaces frequently in audit. A reporting team applying a “delivered” emission factor — one that already includes T&D losses — to its electricity consumption is implicitly double-counting unless it correspondingly excludes T&D losses from Scope 3 Category 3. The clean approach is to use a generation-based emission factor for Scope 2 (covering the emissions at the power plant) and report T&D losses separately in Scope 3 Cat 3, with the loss factor for the relevant grid documented.

For the full Scope 3 Category 3 treatment, see the GHG Protocol Scope 3 Standard reference page.

Geographic Market Boundaries

Quality Criterion 6 — same-market issuance and use — is the most operationally consequential of the eight criteria. The market boundary determines whether an EAC issued in one location can be used to cover consumption in another, and the rules differ by jurisdiction.

What constitutes a market

The Guidance defines a market as the geographic area within which contractual instruments can flow without crossing a regulatory or grid boundary. The default unit is the country. Where multiple countries operate within a single integrated market — the European single market under the AIB framework, the AIB membership and EU single market combination — the market boundary expands to cover that integrated zone. Where a country operates an EAC system distinct from its neighbours’ (Poland with its national system, the post-Brexit United Kingdom), the market boundary contracts back to the national level.

The European single market

The European single market is the most complex case and the one most subject to recent change. As of 2024, RE100 redefined the European single market boundary to require all three of: EU single market membership, AIB membership, and grid connection to a country meeting the first two. The Scope 2 Guidance does not name this redefinition (it predates it by nine years), but in practice the AIB market boundary is the operational definition that auditors apply. The 2024 redefinition has consequences: the United Kingdom, Poland, Bulgaria, Romania, and several Balkan states fell outside the AIB single market, requiring local EACs for local consumption. The 2026 revision is expected to formalise the operational boundary in the Guidance text itself.

U.S. markets

The United States operates as a single national market for the purposes of voluntary REC retirement, with sub-market consideration through the eGRID subregions for location-based factors. State-level Renewable Portfolio Standard (RPS) markets are distinct compliance markets that operate alongside the voluntary REC market; RECs used for compliance with a state RPS cannot be double-claimed for voluntary purposes.

Markets without EAC infrastructure

In markets without a domestic EAC system, the practical options are: (1) accept that the market-based method is not applicable and report only the location-based number; (2) procure I-RECs where the I-REC Standard Foundation has issued in that country; (3) use Tier 4 (residual mix) where one is published, or Tier 5 (location-based as market-based fallback) where it is not. The choice is documented and disclosed.

Steam, Heat, and Cooling

The Scope 2 Guidance covers steam, district heat, and district cooling alongside electricity. The factor sourcing is structurally different and is one of the most under-documented areas of Scope 2 reporting.

Purchased steam

The emission factor chain for purchased steam runs from the upstream fuel through the boiler efficiency to the delivered steam. The default approach is supplier-specific: the steam supplier discloses its fuel input, boiler efficiency, and delivered steam, and the buyer applies the resulting factor. Where the supplier does not disclose, the Guidance permits the use of national or regional defaults — typically published by the national inventory or by regional steam associations. Practitioners should note that the supplier-specific factor is a Tier 1-equivalent pathway, while a national default sits at the bottom of the implicit hierarchy.

District heat

District heating systems supply hot water or low-pressure steam from a centralised plant — often a co-generation facility, an industrial waste heat recovery system, or a dedicated heating boiler — to multiple buildings through an insulated pipe network. The emission factor is supplier-specific where disclosed; where not, national factors for district heating are published in many European countries and increasingly elsewhere.

District cooling

District cooling supplies chilled water from a centralised plant, typically using grid electricity or natural gas to power chillers, or recovering waste heat through absorption chillers. The Scope 2 emission factor is the electricity or gas factor for the energy input, scaled by the chiller efficiency and the network losses. Few national defaults exist; supplier-specific disclosure is increasingly the standard, particularly in the dense urban centres where district cooling is most prevalent.

Renewable Electricity Claims and Zero-Emission Factors

One of the most-asked and most-misunderstood questions about market-based Scope 2: when is a zero figure legitimate?

A zero market-based Scope 2 figure for electricity is technically possible and has a defined meaning under the Guidance. It requires that every MWh of consumption is matched by a contractual instrument that satisfies all eight Quality Criteria, and that the instrument’s emission rate (Criterion 8) is zero or near-zero. In practice, this means every MWh covered by retired EACs from wind, solar, geothermal, or qualifying hydro generation; sourced in the same market as consumption; vintage-aligned; with retirement evidence in the registry.

What it does not mean: that the company physically consumed renewable electricity at the moment of consumption. The market-based figure is a contractual measure, not a physical measure. The location-based figure — required to be reported in parallel — captures the physical reality of the grid the company is exposed to. A company with zero market-based Scope 2 and 0.40 kg CO2e/kWh location-based Scope 2 is making a specific, audited contractual claim while disclosing that its physical grid consumption is grid-average. Both are true, both are required, and the dual-reporting architecture is what makes the contractual claim credible without obscuring the physical reality.

The additionality debate sits adjacent to this. The Guidance does not require additionality for Tier 1 eligibility — an EAC from an old wind farm satisfies the eight Quality Criteria as readily as one from a new project. RE100’s 1 January 2024 update layered a 15-year asset-age rule on top of the Guidance to direct procurement toward newer assets, but the underlying GHG Protocol Quality Criteria do not include additionality as a hard test. The 2026 revision is examining whether to import a stronger additionality signal — particularly through hourly matching — into the Guidance directly.

Interaction with the Corporate Standard

The Scope 2 Guidance is an amendment to the GHG Protocol Corporate Standard and inherits its architecture wholesale. Five interactions matter operationally.

Consolidation approach. The choice of operational control, financial control, or equity share is set at the company level under the Corporate Standard. Scope 2 inherits this choice — there is no option to use a different consolidation approach for Scope 2 than for Scope 1. The boundary alignment is a hard rule.

Base year recalculation. The Corporate Standard requires base-year recalculation when significant structural changes occur — acquisitions, divestments, methodology changes, or factor source changes that materially affect inventory totals. A change in Scope 2 factor source (for example, switching from one published grid factor to another) is a recalculation trigger if the change is material. The Guidance does not relax this requirement.

Leased assets. The Corporate Standard’s rules for leased assets carry through to Scope 2. Under operational control, leased buildings where the lessee operates the electricity supply are in the lessee’s Scope 2; landlord-controlled supply is the landlord’s. Under financial control, the rule is consolidation-driven. The leased-asset boundary is one of the most-litigated areas in Scope 2 audit.

Franchises and subsidiaries. Scope 2 from franchises is in the franchisor’s inventory only where the franchisor has operational or financial control. Subsidiaries are treated under the chosen consolidation approach.

Inventory principles. The seven principles of the Corporate Standard — relevance, completeness, consistency, transparency, accuracy, plus the two governing principles — apply to Scope 2 reporting throughout. Comparability across years and across companies is the principle most directly served by the dual-reporting requirement and the Quality Criteria.

Interaction with SBTi

The SBTi Corporate Net-Zero Standard uses the GHG Protocol Scope 2 Guidance as its technical foundation for Scope 2 measurement. The interaction operates at three levels.

SBTi V1.3.1 — the operative version through most of 2026. Under V1.3.1, companies set Scope 2 reduction targets measured against the market-based method (the dominant practice) or, alternatively, against an RE100-style renewable electricity procurement target. The accounting approach is fully aligned with the Scope 2 Guidance — the same Quality Criteria, the same hierarchy, the same instrument recognition.

SBTi V2.0 draft — the trajectory. The V2.0 draft, in second consultation as of November 2025, signals significant tightening of the Scope 2 expectations:

• Dedicated Scope 2 target. Scope 2 becomes a separate target line, no longer combinable with Scope 1 in a single reduction figure.
• Hourly matching. Procurement must align with consumption on an hourly basis, sourced from the same market — a substantial step beyond the “reasonably close” annual matching the current Guidance permits.
• Same-market sourcing tightening. The geographic boundary requirements harden, with explicit alignment to the Scope 2 Guidance’s market-boundary rules.

The V2.0 trajectory is significant because it pre-empts what the 2026 GHG Protocol revision is examining. A company designing its procurement strategy today should anticipate that hourly matching, currently best practice, will become the floor for SBTi-validated Scope 2 targets — and probably the floor for the revised Scope 2 Guidance — over the late 2020s.

Interaction with CSRD / ESRS E1

The European Sustainability Reporting Standards’ E1 standard on climate change requires substantial energy and emissions disclosure. The Scope 2 Guidance is the technical foundation for two of the most consequential E1 datapoints.

E1-5 Energy consumption and mix. E1-5 requires disclosure of total energy consumption disaggregated by source, including the share of electricity from renewable and non-renewable sources, and the energy intensity per unit of revenue. The Scope 2 Guidance’s contractual instrument architecture is what allows the renewable share to be reported with auditable provenance.

E1-6 Gross Scope 1, 2, 3 and total GHG emissions. E1-6 explicitly requires Scope 2 to be reported using both the location-based and market-based methods — the dual-reporting requirement is mandatory under ESRS E1, not optional. The Quality Criteria and the emission factor hierarchy directly govern how the market-based number is calculated. The location-based number is calculated using grid-average factors per the Guidance.

Assurance implications. CSRD requires limited assurance on sustainability statements from initial implementation, transitioning to reasonable assurance over the late 2020s. The Quality Criteria are the most-checked element of the Scope 2 calculation under assurance — every retired EAC, every PPA, every supplier-specific rate must be traceable to a registry record or a contract, with vintage and market boundary documented.

For the full ESRS E1 datapoint mapping, see the CSRD / ESRS E1 reference page.

Interaction with IFRS S2 and the SEC Rule

IFRS S2. The IFRS Sustainability Disclosure Standards’ S2 (Climate-related Disclosures), published by the ISSB in 2023, requires Scope 1, 2, and 3 emissions disclosure aligned with the GHG Protocol. For Scope 2 specifically, IFRS S2 references the Greenhouse Gas Protocol Corporate Accounting and Reporting Standard and the Scope 2 Guidance, and permits both location-based and market-based reporting. The S2 disclosure architecture is compatible with — and in practice converges on — the dual-reporting requirement.

U.S. SEC climate disclosure rule. The SEC rule, finalised in 2024, requires accelerated and large accelerated filers to disclose Scope 1 and Scope 2 emissions where material. The rule defaults to location-based Scope 2 as the primary required disclosure; market-based Scope 2 is permitted as additional disclosure and is widely used by registrants making renewable procurement claims. Scope 3 is excluded from the rule. The SEC’s choice of location-based as the primary disclosure reflects the regulatory preference for the more conservative, less-discretionary measure; the market-based number remains the procurement-strategy disclosure that most registrants pair with it.

Interaction with RE100

RE100 is the procurement framework that sits on top of the Scope 2 Guidance. Where the Guidance defines the inventory accounting rules — what counts, how it’s measured, what’s eligible — RE100 defines what a “100% renewable electricity” claim requires beyond the inventory level. The two are tightly aligned but not identical.

What RE100 adds. A 100 GWh annual consumption threshold for membership; sector exclusions (no fossil-fuel companies); a target year not later than 2050 with interim milestones; the 1 January 2024 15-year asset age rule (≥85% of grid procurement from assets ≤15 years old); biomass and hydropower sustainability requirements; the post-2027 CDP cycle requirement that every claim be evidenced by a registry cancellation statement. None of these are in the Scope 2 Guidance.

What RE100 inherits. The eight Quality Criteria; the contractual instrument architecture; the same-market sourcing requirement; the integrity infrastructure of the EAC registries.

Why a company can be RE100-compliant with non-zero market-based Scope 2. Three legitimate reasons: (1) RE100 covers electricity only, while Scope 2 includes steam, heat, and cooling — a 100% renewable electricity company may still report Scope 2 emissions from purchased heat; (2) some EACs that satisfy RE100 still carry residual emission factors under Criterion 8 (certain biomass certificates with documented life-cycle factors); (3) annual matching versus hourly matching gaps mean some hours of consumption may not be perfectly matched even when the annual aggregate balances.

For the full RE100 treatment, see the RE100 Technical Criteria reference page.

The 2026 GHG Protocol Revision

The Scope 2 Guidance is in active revision. The 2015 text remains operative as of May 2026, but the GHG Protocol Steering Committee has stood up a structured revision process that is expected to deliver a final revised Guidance in 2027–2028. The contours of the revision are visible enough today to inform procurement decisions made in 2026.

The revision architecture

The revision is being delivered through a Steering Committee, a series of Technical Working Groups (TWGs), and staged public consultation. The TWGs that bear most directly on Scope 2:

• Market-Based Accounting TWG. Examining hourly matching, deliverability, the U.S. residual mix gap, and the future of unbundled EAC eligibility. The most consequential workstream for Scope 2 specifically.
• Land Sector and Removals TWG. Adjacent — touches Scope 2 only through the bioenergy and biomass cross-cutting questions.
• Reporting TWG. Examines disclosure architecture and may reshape how dual reporting is presented.

The November 2022 launch produced a public survey across the suite. The March 2023 Scope 2 Survey results identified four issue areas as highest priority. Technical drafts circulated through 2024–2025. Public consultation has been staged through 2025 and into 2026. Final revised text is expected to publish in 2027–2028.

The four issues under live debate

As of May 2026, the four substantive issues most likely to reshape the operative text:

1. Hourly / granular matching. Whether and how to require hourly matching of EAC retirements to consumption, replacing or supplementing the current annual “reasonably close” rule. The trajectory points strongly toward requirement, but the timeline and the threshold (mandatory hourly, mandatory monthly with hourly best practice, or tiered matching) are unresolved. Hyperscale technology and major sustainability-leading companies have already moved to 24/7 carbon-free energy procurement on a voluntary basis, anticipating the requirement.
2. Deliverability tightening. Whether the same-market boundary should be tightened to require physical deliverability — that is, that the renewable generation be on the same grid as the consumption, not just the same market jurisdiction. The EU’s RFNBO framework and Google’s 24/7 CFE methodology both operate on a deliverability test.
3. The U.S. residual mix gap. The absence of a published U.S. national residual mix is the most operationally consequential gap in the global Scope 2 system. The revision is examining whether to require a residual mix calculation for U.S. markets, and if so, how it should be developed and maintained — by EPA, by a private body, or by a hybrid.
4. The future of unbundled EACs. Whether unbundled EAC purchases should remain Tier 1 eligible, or whether the hierarchy should be restructured to privilege bundled instruments and PPAs. Adjacent frameworks (RE100’s 15-year rule, SBTi V2.0’s hourly matching) have moved in this direction; whether the Guidance follows is the open question.

This section will be the first updated when the revised Guidance publishes. Check back through the GreenCalculus changelog at /changelog/.

Common Misinterpretations

Seven high-frequency misreadings of the Scope 2 Guidance. Each is the kind of error that surfaces in corporate sustainability reports, supplier briefs, and consultancy decks — and each is the kind of error assurance providers catch under ISAE 3410.

Common Reporting Errors

Eight technical errors that surface repeatedly during ISAE 3410 assurance and the CDP reporting cycle:

1. Using location-based factors as the market-based figure without disclosure. Tier 5 is a legitimate fallback only when no higher-tier factor is available, and must be disclosed as a non-representative fallback. Using the location-based factor as the market-based number by default, without checking for higher-tier instruments, is non-compliance.
2. Applying EAC factors before verifying same-market sourcing. Criterion 6 failures are among the most common audit findings. Buying I-RECs from one country to cover consumption in another is non-compliant unless an explicit single-market boundary covers both.
3. Including T&D losses in Scope 2 instead of Scope 3 Cat 3. Either by using a delivered factor for Scope 2 without correspondingly excluding T&D losses from Scope 3 Cat 3, or by reporting T&D losses in both. The clean approach is generation-based factors for Scope 2 and separate T&D loss reporting in Scope 3 Cat 3.
4. Using annual averages for market-based when instruments are time-specific. A company with quarterly EAC retirements should reconcile by quarter, not by full-year average. This is increasingly important as hourly matching becomes the trajectory direction.
5. Treating unbundled RECs as supplier-specific contracts. Unbundled RECs sit at Tier 1 if they satisfy all eight criteria, but they are not supplier-specific contracts (Tier 3). The distinction matters for provenance documentation and assurance.
6. Applying the market-based method to steam and heat when no instrument exists. Where no contractual instrument for steam or heat is available, the residual or default factor is applied, with disclosure. Substituting a renewable electricity factor for purchased steam is non-compliance.
7. Not reconciling location-based to market-based in the inventory. Both figures must be auditable separately and against each other. Inventories that report a market-based figure without a parallel location-based reconciliation cannot be assured under ISAE 3410.
8. Misapplying GWP basis (AR5 vs AR6) to the electricity emission factor. Grid factors are typically published on an AR5 or AR6 basis depending on the source vintage and the publishing body’s policy. Mixing AR5 factors with an AR6 inventory introduces silent error. The GHG Protocol Corporate Standard requires AR6 from the 2026 revision; older factor sources should be re-expressed before use.

Worked Examples

Four worked examples covering the most-common reporting situations. Numbers are illustrative and hardcoded — they show the calculation chain, not current factor values for any specific market.

Example A — UK manufacturer with REGOs

A UK manufacturer consumes 10,000 MWh of grid electricity in 2025. It procures 8,000 MWh of UK-issued REGOs, retired in the Ofgem registry, vintage 2025, from disclosed wind generation.

• Location-based. 10,000 MWh × 0.207 kg CO2e/kWh (DEFRA 2025 UK grid factor) = 2,070 t CO2e.
• Market-based. 8,000 MWh × 0 kg CO2e/kWh (REGO-covered, Tier 1) + 2,000 MWh × UK residual mix factor (Tier 4) = market-based emissions on the residual portion only. If the residual mix factor is 0.310 kg CO2e/kWh, the market-based figure is 620 t CO2e.
• Disclosure. Both figures reported under E1-6. The 2,000 MWh uncovered portion is disclosed at Tier 4 with the residual mix factor cited.

Example B — Multinational with no EAC market available

A multinational subsidiary consumes 5,000 MWh in a market with no domestic EAC system, no published residual mix, and no I-REC issuance. The parent company has not procured cross-market instruments.

• Location-based. 5,000 MWh × national grid factor (IEA-published) = location-based emissions.
• Market-based. Tier 4 (residual mix) is unavailable. Tier 5 (location-based as fallback) is applied. The figure is identical to the location-based number.
• Disclosure. The market-based figure is reported with a disclosure note: “Tier 5 fallback applied; no higher-tier instruments available in this market.” Internal stakeholders are flagged that I-REC issuance, when it becomes available, would create a Tier 1 procurement option.

Example C — Data centre with a physical PPA

A data centre operator consumes 50,000 MWh at a single site. It has a physical PPA with a new-build wind farm in the same grid, supplying 45,000 MWh annually with bundled EACs.

• Location-based. 50,000 MWh × eGRID subregion factor for the relevant NERC subregion = location-based emissions.
• Market-based. 45,000 MWh × 0 kg CO2e/kWh (PPA-bundled EAC, Tier 1) + 5,000 MWh × Tier 5 residual (no U.S. published residual mix). The 5,000 MWh uncovered portion is reported at Tier 5 with disclosure.
• Documentation. Bundled EAC retirement statements from the relevant U.S. registry; PPA contract showing explicit EAC conveyance; vintage matching in the registry record. The calculation is fully traceable.

Example D — U.S. data centre facing the no-residual-mix problem

A U.S. data centre consumes 20,000 MWh in a NERC subregion. It has procured 12,000 MWh of unbundled RECs from the same NERC subregion (same-market under U.S. interpretation) but has no PPA. The U.S. has no published national residual mix.

• Location-based. 20,000 MWh × eGRID subregion factor = location-based emissions.
• Market-based. 12,000 MWh × 0 kg CO2e/kWh (unbundled REC, Tier 1, assumes all eight Quality Criteria satisfied) + 8,000 MWh × eGRID subregion factor (Tier 5 fallback). With no U.S. published residual mix, Tier 4 is unavailable; Tier 5 applies on the uncovered portion.
• The transparency gap. The 8,000 MWh uncovered portion is calculated at the gross grid average rather than at a residual-mix-adjusted rate. In a market with widespread voluntary REC retirement, this systematically understates the implicit grid intensity facing buyers who have not procured. This is one of the four issues the 2026 revision is examining directly. Until resolved, U.S. companies should disclose the absence of a residual mix as a methodological note.

Assurance and Audit Considerations

The Scope 2 calculation is one of the most-tested elements of any GHG inventory under ISAE 3410 (the assurance standard for GHG statements) and ISAE 3000 (the broader non-audit engagement standard). Assurance providers focus on five areas.

Factor traceability. Every emission factor used must have a documented source, date, and version. A 2025 Scope 2 inventory using a 2019 grid factor is a finding unless the use of an older factor is methodologically justified and disclosed. Factor source changes between reporting years are recalculation triggers under the Corporate Standard.

Instrument documentation. Every contractual instrument applied at Tier 1 or Tier 2 requires documentation: EAC cancellation statements from the issuing registry, PPA contracts showing explicit EAC conveyance, supplier-specific rate disclosures with the supplier’s underlying calculation. Holding an unretired certificate at year-end is a Criterion 4 failure.

Reconciliation to metered consumption. The MWh consumption applied in the Scope 2 calculation must reconcile to metered records — utility bills, sub-meter readings, or the equivalent. Estimated consumption is permitted where metering is unavailable but must be documented and consistently applied.

Quality Criteria evidence. Each of the eight Quality Criteria must be evidenced for each Tier 1 instrument: registry record (Criteria 2, 3, 4), vintage documentation (Criteria 5, 7), market boundary documentation (Criterion 6), and emission rate documentation (Criterion 8). The audit trail is per-instrument, not per-portfolio.

Dual-reporting reconciliation. The location-based and market-based figures must be calculable from the same underlying consumption data. Auditors test that both numbers can be reproduced from the same inventory; inventories where the two methods cannot be reconciled to a common consumption baseline cannot be assured.

For a related treatment, see the ISO 14064-1 reference page, which provides the broader quantification standard that ISAE 3410 maps to.

Implementation Checklist

For a company implementing the Scope 2 Guidance for the first time, or restructuring an existing inventory, the practical workflow runs as follows.

1. Confirm the consolidation boundary. Operational, financial, or equity share — set at the company level under the Corporate Standard, applied uniformly to Scope 2.
2. Compile metered consumption by market. Disaggregate by country, by sub-national region where eGRID-equivalent factors apply, and by energy type (electricity, steam, heat, cooling).
3. Identify available contractual instruments per market. EAC system, PPA market, green tariff availability, residual mix publication. Document the instrument inventory.
4. Apply the five-tier emission factor hierarchy. For each consumption point, identify the highest-tier factor available that satisfies all eight Quality Criteria. Where multiple instruments cover the same consumption, document the allocation.
5. Source residual mix or grid-average factors as fallbacks. Tier 4 (residual mix) where published; Tier 5 (location-based as market-based fallback) only where no higher tier is available.
6. Calculate and cross-check both location-based and market-based. Apply the location-based factors and the market-based factors to the same consumption baseline. Reconcile the two figures and document the difference.
7. Document and retain instrument evidence. EAC cancellation statements; PPA contracts with explicit EAC conveyance language; supplier-specific rate disclosures; vintage and registry records. Per-instrument, not per-portfolio.
8. Reconcile to financial metering records. The consumption baseline used for Scope 2 must reconcile to utility bills and sub-meter readings.
9. Prepare for assurance review. Compile the audit pack: factor sources with dates, instrument evidence per Quality Criterion, dual-reporting reconciliation, T&D loss reporting in Scope 3 Cat 3 (separate from Scope 2).
10. Disclose under the relevant framework. CSRD ESRS E1-5 and E1-6 for European entities; IFRS S2 for ISSB-aligned reporting; the SEC rule for U.S. accelerated filers; CDP for voluntary disclosure; SBTi for target-aligned reporting.

Frequently Asked Questions

Sources and References

Every numerical claim and methodological statement in this article reconciles to the primary sources below. Where the GHG Protocol has published a definitive document on a topic, the primary source is cited directly; secondary commentary is used only for interpretation.

Primary GHG Protocol documents

• WRI & WBCSD, GHG Protocol Scope 2 Guidance: An amendment to the GHG Protocol Corporate Standard, January 2015. The operative text as of May 2026.
• WRI & WBCSD, The Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (revised edition, 2004), with the 2026 revision in progress.
• WRI & WBCSD, Corporate Value Chain (Scope 3) Accounting and Reporting Standard, 2011, with the 2026 revision in progress.
• GHG Protocol, Scope 2 Survey Results, March 2023.
• GHG Protocol, corporate standards revision process documentation, 2022–2026. Steering Committee outputs, Market-Based Accounting Technical Working Group materials, and public consultation drafts published through the GHG Protocol website.

Underpinning standards and adjacent frameworks

• Science Based Targets initiative, Corporate Net-Zero Standard, Version 1.3.1, April 2026, and Corporate Net-Zero Standard V2.0 Second Consultation Draft, November 2025.
• RE100 (Climate Group & CDP), RE100 Technical Criteria + Appendices, April 2025 release.
• European Sustainability Reporting Standards, ESRS E1 (Climate change). EFRAG, 2023 (EU Delegated Act).
• IFRS Sustainability Disclosure Standards, IFRS S2 (Climate-related Disclosures). ISSB, 2023.
• U.S. Securities and Exchange Commission, climate-related disclosure rule, 2024.
• ISO 14064-1, Greenhouse gases — Part 1: Specification with guidance at the organization level for quantification and reporting of greenhouse gas emissions and removals.
• ISAE 3000 / ISAE 3410 — assurance standards for non-audit engagements and GHG statements.

Emission factor sources

• International Energy Agency (IEA), Emissions Factors, annual editions; Global Energy Review 2026.
• U.S. Environmental Protection Agency, eGRID, latest published edition.
• UK Department for Environment, Food & Rural Affairs (DEFRA), Greenhouse gas reporting: conversion factors, annual editions.
• Association of Issuing Bodies (AIB), European Residual Mixes, annual editions; European Energy Certificate System (EECS) Rules.
• Environment and Climate Change Canada, national grid factors.

EAC system references

• I-REC Standard Foundation, I-REC Code.
• Green-e, Green-e Renewable Energy Standard for Canada and the United States.
• Ofgem, REGO documentation.
• Clean Energy Regulator (Australia), Renewable Energy (Electricity) Act 2000 and LGC scheme documentation.
• Central Electricity Regulatory Commission (India), REC Regulations.
• METI / J-Credit / NFC scheme documentation (Japan).

Related GreenCalculus reference pages

• GHG Protocol Corporate Standard
• GHG Protocol Scope 3 Standard
• SBTi Corporate Net-Zero Standard
• RE100 Technical Criteria
• CSRD / ESRS E1
• ISO 14064-1
• IPCC AR6
• UK DEFRA Emission Factors
• Scope 2 emissions
• Scope 2 (location-based method)
• Scope 2 (market-based method)
• Scope 3 emissions
• Energy Attribute Certificates
• Residual mix
• Electricity emission factor
• Scope 2 location-based vs market-based
• Scope 2 electricity methodology
• Scope 2 market-based methodology
• Scope 2 Electricity Calculator
• IEA Grid Emission Factors 2026
• DEFRA Emission Factors
• SBTi Readiness Checklist

What changed in this revision

Updated 10 May 2026. Initial publication. Reflects the GHG Protocol Scope 2 Guidance as it stands in May 2026: the operative January 2015 text, the eight Quality Criteria, the five-tier emission factor hierarchy, the residual mix and T&D loss treatment, the geographic market boundary architecture, the steam/heat/cooling coverage, and the active 2026 revision (Steering Committee, Market-Based Accounting Technical Working Group, four substantive issues under live debate, finalisation expected 2027–2028). Cross-references to the SBTi Corporate Net-Zero Standard V1.3.1 and V2.0 draft, RE100 Technical Criteria April 2025 release, CSRD ESRS E1, IFRS S2, and the U.S. SEC climate disclosure rule.