Scope 2 Market-Based Method: GHG Protocol Methodology, Instrument Equivalence, and the Emission Factor Hierarchy
A reference for the GHG Protocol Scope 2 market-based method as defined in the Scope 2 Guidance (2015) and as it interacts with CSRD ESRS E1 mandatory disclosure (2023), the SBTi Corporate Net-Zero Standard instrument rules (V1.3.1 today, V2.0 from February 2027), and the 2026 GHG Protocol Corporate Standard revision currently in consultation. Defines the instrument equivalence problem, the canonical five-tier emission factor hierarchy, the double-claiming taxonomy with six numbered failure modes, the EAC market maturity matrix across thirteen jurisdictions, the additionality debate as three named positions, and the methodology version history as a standards-document log. Three audit-record worked examples — single-site Tier 3 supplier disclosure, multi-site mixed-tier portfolio, sold-EAC double-claim failure — verify arithmetic against the Scope 2 Electricity Calculator. Aligned to GHG Protocol Corporate Standard and Scope 2 Guidance (2015 amendment).
This page is the deep treatment of the market-based method specifically. The Scope 2 Electricity methodology covers the complete inventory workflow including grid factor lookup, multi-site aggregation, and the Scope 3 Cat 3 T&D companion; this page covers the contractual claim architecture, the emission factor hierarchy that governs which factor applies to which kWh, the instrument equivalence problem at the heart of every audit dispute, and the version history that determines whether historical inventories require methodology restatement. For the head-to-head method comparison see Scope 2 location-based vs market-based; for the operational calculator see the Scope 2 Electricity Calculator.
The Instrument Equivalence Problem
Named concept · Citable definition
The instrument equivalence problem
The arithmetic of the GHG Protocol market-based method treats every retired energy attribute certificate as numerically equivalent on the unit-of-MWh basis, so a bundled REGO retirement, a bundled GO retirement, an I-REC retirement, and a contracted PPA volume each produce the same MB inventory contribution per kWh covered — but the four are not the same disclosure under CSRD ESRS E1 transition-plan narrative, will not all qualify under SBTi Corporate Net-Zero Standard V2.0 once its generator-age and deliverability limits apply, and are not the same instrument under emerging additionality scrutiny.
⚐ The central editorial tension this page resolves
A market-based zero achieved through 1,000 MWh of bundled REGOs purchased on the secondary market and a market-based zero achieved through 1,000 MWh of contracted output from a new-build solar PPA produce identical MB inventory totals: 1,000,000 × 0.0 = 0 kgCO₂e in both cases. The disclosures, however, are not equivalent. The first is acceptable under SBTi V1.3.1 if the certificates come from the same market, but under V2.0 it fails if the generator is more than 15 years old, and it needs a stronger transition-plan narrative under ESRS E1. The second anchors a credible ESRS E1 transition plan and is the audit-grade benchmark. The arithmetic equivalence is real; the disclosure equivalence is fictional. The instrument equivalence problem is the structural reason a Scope 2 MB total cannot be read in isolation — it must be read together with the instrument basis, the additionality posture, the residual mix treatment for any unmatched portion, and the framework against which the disclosure is filed. Every section of this page exists to give reporters and auditors the apparatus to read the MB total in the round.
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What Market-Based Actually Means: The Contractual Claim Architecture
The market-based method is routinely glossed as “buying low-carbon electricity.” That gloss is wrong in a way that matters at audit. The reporter does not buy low-carbon electricity in any physical sense — the electrons arriving at the meter are dispatched from whichever generators happened to be running on the grid in the hour the meter recorded consumption, and those generators are determined by merit-order economics that the reporter has no contractual ability to alter. Wind generation cannot be physically routed to a specific meter; nuclear baseload cannot be allocated to a corporate buyer. Physical electricity is fungible at the bus-bar — it is the same commodity once it enters the grid, regardless of which generation asset produced it.
What the reporter actually buys, in any market-based contract, is two things sold together or separately: (1) the electricity itself — the right to consume electrons from the grid, settled in kWh and priced in the local wholesale or retail market — and (2) the contractual claim over the environmental attribute of the generation associated with those kWh — the renewable origin, the zero-emission character, the fuel type — settled in MWh and traded as a separate financial or registry instrument. The two are severable. They can be sold together (a “bundled” instrument: the energy and its attribute pass to the same buyer in one transaction), or separately (the energy goes to one party at one price, the attribute goes to another party at another price).
Figure 3.1 — The energy/attribute severability diagram
Two flows from one renewable generation event. The physical flow follows merit-order grid dispatch and is identical to any other electron’s path. The contractual flow follows the certificate registry and can be assigned to any buyer who retires the certificate. The two are independent. Audit confusion in §7 failure modes (1) and (2) tracks back to readers conflating these flows.
Physical flow — fungible
1 MWh of electricity
↓ generation onto grid bus-bar
↓ merit-order dispatch by grid operator
↓ commingled with all other generation
↓ delivered to whichever meter is consuming
↓ settled in kWh through retail tariff
The reporter cannot trace specific electrons. The electricity is fungible at the bus-bar. Physical delivery is a property of the grid, not the contract.
Contractual flow — assignable
1 EAC representing 1 MWh attribute
↓ EAC issued by registry per MWh generated
↓ EAC held in registry account
↓ EAC sold (bundled with energy or unbundled)
↓ EAC retired against specific consumption claim
↓ retirement statement issued for audit
The certificate is the contractual claim. It can travel with the energy (bundled) or independently (unbundled). Once retired, it cannot be re-used by any other reporter.
This architecture is why bundled and unbundled instruments differ in disclosure significance even when their MB arithmetic is identical. A bundled REGO retired against a 1 MWh consumption block produces a contractual claim that the energy and its attribute came from the same wind farm — but that claim says nothing about whether the wind farm would have been built without the REGO market. An unbundled REGO purchased on the Ofgem secondary market and retired against the same consumption block produces an identical contractual claim, but the linkage to specific generation is even thinner — the secondary market is a financial instrument layer, not a procurement channel. A contracted PPA for new-build generation produces a contractual claim plus a documented capital commitment — the wind farm exists because of the PPA. The arithmetic erases this distinction; the disclosure narrative cannot. The instrument equivalence problem of §2 is the symptom; the contractual claim architecture is the underlying mechanism.
The Scope 2 Emission Factor Hierarchy
Named concept · Citable definition
The market-based emission factor hierarchy
The five kinds of market-based data in Table 6.3 of the GHG Protocol Scope 2 Guidance (2015), from most precise to least precise: energy attribute certificates and contracts that convey them, contracts where no certificate exists or is needed, supplier or utility emission rates, residual mix, and other grid-average factors. Applied per kWh.
Table 6.3 of the 2015 Guidance lists these five rows without numbers. We call them Tier 1 to Tier 5 here and on our other Scope 2 pages; the numbers are our label, not GHG Protocol wording. The Guidance says the table is a hierarchy of precision, not a preferred hierarchy of procurement methods, so it does not favour buying from a supplier over contracting with a generator. Any contractual instrument has to meet the Scope 2 Quality Criteria in Table 7.1. Each tier below has its own evidence and its own audit risk, and different tiers can apply to different kWh in the same inventory.
EFgrid × 1.10 to 1.20 with explicit audit flag. The Scope 2 Electricity Calculator uses 1.15× as default.
Figure 4.1 — Tier selection flowchart, applied per kWh of consumption
grid × 1.10 to 1.20 with audit flag (GreenCalculus operational pattern, not GHG Protocol-canonical). No → Tier 5 apply location-based grid factor as fallback.Two structural points. First, tier selection is per-kWh, not per-site or per-portfolio — a single site can use Tier 1 on its PPA-covered consumption, Tier 4 on its unmatched consumption, and Tier 3 on a separate tariff for a sub-meter, all in the same inventory. Second, the tier hierarchy is downward-only: the reporter never voluntarily moves to a less-specific tier when more-specific evidence is available. Tier 5 is not a choice — it is a fallback. The audit pattern is to verify the tier selection per kWh aligns to the highest evidence available, and to flag any case where a lower tier appears to have been applied with higher-tier evidence on hand.
The Instrument Equivalence Problem — Full Analytical Treatment
The arithmetic of the market-based method renders nine instrument types and edge cases as numerically equivalent on the unit-of-MWh basis when the supplier or contract factor is zero. The disclosures, additionality posture, and audit risk diverge sharply. Table 5.1 is the canonical reference — readers citing this page should cite “GreenCalculus Scope 2 Market-Based Methodology v2.0, Table 5.1: Instrument Equivalence Matrix.”
| Instrument | Quality Criteria pass | CDP | CSRD ESRS E1 | SBTi V2.0 (from Feb 2027) | Residual on unmatched | Audit risk |
|---|---|---|---|---|---|---|
| REGO bundledUK · Ofgem | Pass — all 7 | Accepted | Accepted | Eligible if within 15 years and same activity pool | AIB UK residual ≈ 0.28064 kg/kWh | Medium |
| REGO unbundledUK · secondary market | Pass — all 7 | Accepted | Accepted with disclosure | Eligible if within 15 years and same activity pool | AIB UK residual ≈ 0.28064 kg/kWh | Medium-high |
| GO bundledEU/EEA · AIB issuing bodies | Pass — all 7 | Accepted | Accepted | Eligible if within 15 years and same activity pool | AIB residual per member state | Medium |
| REC voluntaryUS · state markets + Green-e | Pass — Green-e certified preferred | Accepted | Accepted with cross-border note | Eligible if within 15 years and same activity pool | EPA eGRID residual per NERC subregion | Medium |
| I-RECAsia/Africa/LatAm · I-REC Standard | Pass — all 7 | Accepted | Accepted with provenance disclosure | Eligible if within 15 years and same activity pool | No published residual; T-0 untraced premium typically | High |
| PPA bundled (physical)Global · direct contract | Pass — all 7 | Accepted | Accepted, narrative recommended | Eligible; same age and pool limits | Per-PPA disclosed factor; residual on uncovered fraction | Low |
| PPA unbundled / VPPAGlobal · CFD + EAC | Pass — all 7 | Accepted | Accepted with project provenance | Eligible; same age and pool limits | Per-PPA disclosed factor; residual on uncovered fraction | Low |
| Self-generation — EACs retainedGlobal · on-site | Pass — direct ownership | Accepted (out of Scope 2 boundary) | Accepted (out of Scope 2 boundary) | Behind-the-meter only; certificates cannot cover grid use | n/a — consumption never enters Scope 2 | Low |
| Self-generation — EACs soldGlobal · trap pattern | Fail — attribute relinquished | Cannot claim | Cannot claim | Cannot claim — attribute is the buyer’s | Residual mix on full on-site consumption | High — failure mode 7.1 |
Three reading patterns. First, arithmetic equivalence ≠ disclosure equivalence: the seven instrument types in rows 1-7 produce identical zero-emission MB contributions per matched kWh, but under SBTi V2.0 some stop qualifying once the generator passes 15 years. V1.3.1 sets no instrument-level additionality test. Second, the audit risk profile rises with the contractual distance from named generation: bundled PPA (row 6) is low-risk because the contract identifies the asset; unbundled REGO (row 2) is medium-high because the secondary market severs the link. Third, self-generation with EACs sold (row 9) is the only structural failure case — every other row produces a defensible disclosure, but selling EACs while claiming the on-site reduction is a Quality Criteria failure regardless of how the arithmetic appears. This is failure mode 7.1 in the taxonomy below.
Jurisdiction-by-Jurisdiction EAC Market Maturity
The market-based method depends on EAC market depth, residual mix availability, and registry maturity in each jurisdiction the reporter operates in. Table 6.1 is the cross-jurisdictional reference — for any multinational reporter, the per-jurisdiction maturity rating informs the audit-risk weight applied to MB claims from that jurisdiction. Fixed values: there is no MasterBrain section for EAC market maturity at v2025.6; the data below is researched and verified at this page’s review date.
| Jurisdiction | EAC instrument | Issuing body | Residual published | Source | Maturity | Cross-border audit risk |
|---|---|---|---|---|---|---|
| United Kingdom0.131 kg/kWh LB | REGO | Ofgem | Yes — AIB | AIB European Residual Mixes (annual) | Established | Low — robust regulator, audit standard |
| Germany0.330 kg/kWh lifecycle | GO (Herkunftsnachweis) | Umweltbundesamt (HKNR) | Yes — AIB | AIB European Residual Mixes (annual) | Established | Low — large active EAC market |
| France0.041 kg/kWh lifecycle | GO | EEX (national agent) | Yes — AIB | AIB European Residual Mixes (annual) | Established | Low — nuclear-dominant grid; GO market shallower than DE |
| Spain0.154 kg/kWh lifecycle | GO (Garantías de Origen) | CNMC | Yes — AIB | AIB European Residual Mixes (annual) | Established | Low — well-developed solar PPA market |
| Netherlands0.254 kg/kWh lifecycle | GO (Garanties van Oorsprong) | VertiCer | Yes — AIB | AIB European Residual Mixes (annual) | Established | Low — mature import market |
| United States — national0.350 kg/kWh LB | REC | State / regional REC tracking systems | Yes — EPA eGRID per NERC subregion | EPA eGRID residual mix tables | Established | Medium — fragmented across state markets |
| US WECC-CAMX (California)0.195 kg/kWh LB | REC (CA-eligible) + WREGIS | WREGIS | Yes — EPA eGRID | EPA eGRID residual mix tables | Established | Low — strong tracking system |
| US RFCE (PJM East)0.272 kg/kWh LB | REC (PJM-EIS GATS) | PJM-EIS GATS | Yes — EPA eGRID | EPA eGRID residual mix tables | Established | Low — high-volume corporate PPA region |
| Singapore0.497 kg/kWh lifecycle | I-REC (Singapore) | EMA / I-REC registry | No | — | Developing | Medium — NEA carbon tax uses LB; MB voluntary |
| Australia0.590 kg/kWh LB | LGC (Large-scale Generation Certificate) | Clean Energy Regulator | Partial — Climate Active method | Climate Active Carbon Neutral Standard | Established | Low — mature scheme; LGC pricing transparent |
| Japan0.477 kg/kWh lifecycle | J-Credit + Green Power Certificate + I-REC | METI / I-REC registry | No | — | Developing | Medium — fragmented instrument types; vintage rules complex |
| India0.671 kg/kWh lifecycle | I-REC + REC (CERC) | I-REC registry / CERC | No | — | Developing | High — coal-dominant grid amplifies MB-LB delta; provenance scrutinised |
| Brazil0.110 kg/kWh lifecycle | I-REC | I-REC registry | No | — | Developing | Medium — hydro-dominant grid; LB already low so MB delta moderate |
| South Africa0.699 kg/kWh lifecycle | I-REC + nascent local instruments | I-REC registry | No | — | Nascent | High — coal-dominant grid amplifies MB-LB delta; thin EAC market |
Two patterns. First, EAC market maturity correlates with audit confidence but not with MB reduction potential: the highest MB-vs-LB delta opportunities are in the highest-LB jurisdictions (India, South Africa) where mature EAC markets do not yet exist. Reporters in these jurisdictions face a tension between the methodological rigor of mature-market claims and the impact magnitude of nascent-market claims. Second, cross-border claims carry their own audit risk regardless of source-jurisdiction maturity: an EU reporter retiring I-RECs from Brazil to cover their Brazilian operations is on solid ground; the same reporter retiring I-RECs from Brazil against their European operations triggers cross-border failure mode 7.3. Geographic correspondence between consumption and EAC retirement is one of the eight Scope 2 Quality Criteria.
The Double-Claiming Taxonomy — Six Failure Modes
Named concept · Citable definition
The double-claiming taxonomy
Six structurally distinct ways a Scope 2 market-based disclosure can claim emission reduction it is not entitled to under the GHG Protocol Quality Criteria, each named, numbered, and characterised by its arithmetic signature so that auditors can detect the failure mode from the inventory output without needing access to underlying contracts.
The taxonomy below is the canonical six. Each is named for citation as “GreenCalculus Scope 2 MB Methodology v2.0, failure mode 7.n.” Failure mode 7.1 is the highest-frequency in production disclosures; 7.5 is the lowest-frequency but the most damaging when it occurs.
0.13096 instead of 0.28064 on the unmatched 50% reports only ~47% of the correct MB total — an understatement of roughly 53%.The Additionality Debate — Three Positions
The methodological status of bundled instruments — REGOs, GOs, RECs — relative to contracted PPAs has been the live debate in Scope 2 reporting since approximately 2022. The debate is not whether MB accounting is valid (it is, under the 2015 Guidance); it is whether the quality of the MB claim depends on the additionality posture of the underlying instrument. Three positions are now coexistent in the standards landscape, each held by a different rule-maker, each with a different disclosure consequence. Reporters navigating all three simultaneously face a coherence problem the standards have not yet resolved.
Position A
GHG Protocol Scope 2 Guidance (2015)
Quality Criteria are sufficient — additionality not required
Table 7.1 of the 2015 Scope 2 Guidance sets out eight Quality Criteria. An instrument must (1) convey the direct emission rate of the generation, (2) be the only instrument carrying that claim, (3) be tracked and retired by or for the reporter, (4) be issued and redeemed as close as possible to the period of consumption, and (5) come from the same market as the consumption. Utility factors must be based on delivered electricity (6). Direct contracts and on-site generation must transfer the claim to the reporter alone (7). A residual mix must be available, or its absence disclosed (8). None of the eight tests additionality. A bundled REGO from existing hydropower can meet them all; the Guidance does not require the reporter to show that the hydropower would not have been built without the REGO market. Position A is the floor — every framework accepts an instrument that satisfies the Quality Criteria as a Scope 2 MB input.
Position B
SBTi Corporate Net-Zero Standard V1.3.1 and V2.0
Additionality required for target progress credit
SBTi separates inventory disclosure (governed by the GHG Protocol) from target rules. Under V1.3.1 a company picks location-based or market-based and uses it for both base year and progress (criterion C9), and RECs must be purchased and used within the same market. There is no project-level additionality test: a certificate that meets those rules counts toward a market-based target. V2.0, published in June 2026 and open for validations from 1 February 2027, adds limits: instruments must be deliverable to the same activity pool (C30) and come from generators commissioned or re-powered within the previous 15 years (C31.3), with a legacy clause for existing long-term contracts. Position B does not invalidate Position A; it adds SBTi-specific rules on top.
Position C
CSRD ESRS E1 transition plan requirement (2023)
Additionality posture must be disclosed in the transition plan
ESRS E1 does not require additionality for the inventory disclosure (Position A holds for the E1-6 reporting line). It does require, in the E1-1 transition plan disclosure, that the reporter narrate their additionality strategy — what proportion of their MB claim is bundled versus contracted, what their procurement strategy is for shifting toward additional instruments, what their dependence on residual mix is. The CSRD position is procedural rather than calculative: the inventory total is calculated under Position A rules, but the transition plan must explain the quality of the claim. Position C makes opacity expensive without changing the arithmetic.
How the three interact for a reporter navigating all three: the inventory total under all three frameworks is the same — Position A governs the calculation. The additional disclosure burden under Position C requires a transition plan narrative that addresses the bundled-versus-contracted mix. Under Position B, a company tracking a location-based target will show different progress from its market-based inventory, and from February 2027 a V2.0 target may exclude instruments from older generators. Reporters who do not pre-empt this divergence in their disclosure narrative face stakeholder confusion when analysts compare the inventory total to the SBTi progress claim and find a gap. The audit-grade response is to disclose the bundled-versus-contracted mix in the inventory commentary, the procurement strategy in the transition plan, and the SBTi method and any excluded instruments in the target progress narrative — three disclosures, one coherent story, no surprises at year-end review. This is the methodology disposition this page recommends.
Methodology Version History
The market-based method has evolved through six identifiable milestones since the GHG Protocol Corporate Standard’s first publication. Reporters using historical inventories for trend analysis or target baseline establishment must understand which milestones triggered methodology restatement requirements (changes that retroactively alter prior-year figures) and which were prospective-only (changes that apply from a forward date with prior-year figures unchanged). Table 9.1 is the standards-document log.
| Date | Document | What changed | Why it matters | Restatement |
|---|---|---|---|---|
| 2001 | GHG Protocol Corporate Standard (initial) | Scope 1, 2, 3 framework defined. Scope 2 specified as “indirect emissions from purchased electricity” without methodological detail on factor selection. | Foundational. No MB method existed. All Scope 2 reporting was implicitly location-based. | No (foundational) |
| 2004 | GHG Protocol Corporate Standard v1.0 (revised) | First formal Corporate Standard publication. Scope 2 boundary clarified; LB method implicit. | Set the boundary for two decades. EACs and PPAs not yet a methodological feature. | No (boundary unchanged) |
| January 2015 | Scope 2 Guidance — publication (Corporate Standard amendment) | Dual-reporting requirement set (§7.1). Market-based method defined. Eight Quality Criteria (Table 7.1). Market-based data hierarchy (Table 6.3). Residual mix concept introduced. The methodological foundation of every Scope 2 MB disclosure since. | The single most consequential milestone. All current MB methodology traces to this document. Pre-2015 inventories using a “renewable” claim without dual-reporting are not comparable to post-2015 dual-disclosure inventories. | Yes — for trend baselines extending pre-2015 |
| 2023 | CSRD ESRS E1 (final) | Mandatory dual disclosure for EU companies in scope. Explicit residual mix factor citation requirement (E1-6). Transition plan additionality narrative requirement (E1-1). Value-chain T&D disclosure expectation. | Position C above. Did not change MB calculation, but changed disclosure burden. EU-domiciled reporters must now address residual mix sourcing and additionality posture explicitly. | No (prospective from FY2024 reporting) |
| June 2026 | SBTi Corporate Net-Zero Standard V2.0 | Position B above. Published June 2026, open for validations from 1 February 2027. Adds activity-pool deliverability and a 15-year generator age limit. V1.3 stays open for submissions until 31 January 2028. | Does not change the inventory MB calculation. Changes which instruments can support a V2.0 target. Existing long-term contracts have a legacy clause. | No (targets set under V2.0 only; inventory unchanged) |
| 2026 (consultation) | GHG Protocol Corporate Standard revision — in consultation | In consultation as of this page’s review date — not finalised. Public consultation on the next Corporate Standard revision is ongoing through 2026. Areas of likely revision include hourly carbon-free energy matching, residual mix governance, and Quality Criteria refinement. The revision is not yet binding methodology. | Reporters tracking the revision should monitor publication timing. Restatement requirements will depend on the final scope of changes. Position monitoring, not action, is the current posture. | Pending — depends on final scope |
Two structural points for trend analysis. First, any Scope 2 trend baseline extending before January 2015 must be restated to the post-2015 dual-reporting basis for comparability. Pre-2015 “renewable energy used” claims do not map to post-2015 LB+MB disclosure. SBTi target baselines anchored before 2015 are not directly comparable to current-year disclosures without methodology restatement. Second, the 2023 CSRD ESRS E1 release did not require restatement because the underlying MB calculation was unchanged — it required additional disclosure (residual citation, transition plan narrative) prospectively from FY2024. SBTi V2.0 is similarly prospective-only: it applies to targets set under it. The 2026 GHG Protocol revision is the next potential restatement trigger, and reporters should plan accordingly while it remains in consultation.
Worked Examples — Audit Records
Three audit-record snapshots at this page’s review date (2026-05-10). Fixed values throughout. Each example replicable in the Scope 2 Electricity Calculator; the calculator’s hash output will match the values shown here as long as MasterBrain v2025.6 is the active version.
Reporting year: 2026 | Reporting framework: UK SECR + CDP
Site: London headquarters, single half-hourly meter
Annual consumption: 2,500,000 kWh
Tariff: Supplier “Green Origin” tariff with disclosed annual factor 0.043 kg CO₂e/kWh — backed by supplier portfolio of REGOs plus residual mix on uncovered fraction; supplier annual disclosure document published Q1 2026
Reporter-held instruments: None (the supplier handles matching at portfolio level)
Tier selection: Tier 3 — supplier-specific rate The non-zero Tier 3 case. Demonstrates that an MB total can be meaningfully below LB without being zero — the supplier-disclosed factor reflects partial portfolio matching.
Tier 3. Question 3 not reached. The supplier disclosure document is the audit evidence.
Reporting year: 2026 | Reporting framework: EU CSRD / ESRS E1
Site 1 — Frankfurt office (Germany): 1,800,000 kWh · 50% bundled GO from existing hydro · supplier factor not disclosed (zero convention) →
Tier 4 on unmatched 50%Site 2 — Lyon R&D centre (France): 1,200,000 kWh · No instruments held →
Tier 5 LB fallback at site levelSite 3 — Madrid manufacturing (Spain): 800,000 kWh · 100% I-REC from new-build solar PPA · supplier factor 0.0 →
Tier 1 contracted rate
Multi-jurisdictional portfolio with three different tier states operating in parallel. Demonstrates per-kWh tier selection at site level with portfolio aggregation under the §7.1 invariant.0.3795 = grid 0.330 × 1.15 untraced premium fallback for AIB-published German residual not yet in MasterBrain). Lyon: no instruments → Tier 5 at site level (LB carries to MB per §7.1 invariant). Madrid: contracted PPA → Tier 1 across all consumption. Three tiers operating across the portfolio simultaneously.
| Site | Country | kWh | Tier(s) | EAC % | LB tCO₂e | MB tCO₂e |
|---|---|---|---|---|---|---|
| Frankfurt | Germany | 1,800,000 | T2 + T3 | 50% GO | 1,800,000 × 0.330 = 594.00 | (900,000 × 0.0) + (900,000 × 0.3795) = 341.55 |
| Lyon | France | 1,200,000 | T4 | 0% | 1,200,000 × 0.041 = 49.20 | 49.20 (LB carries to portfolio per §7.1) |
| Madrid | Spain | 800,000 | T2 | 100% I-REC PPA | 800,000 × 0.154 = 123.20 | (800,000 × 0.0) = 0.00 |
| Portfolio totals | 3,800,000 | — | — | 766.40 tCO₂e | 390.75 tCO₂e | |
Reporting year: 2026 | Reporting framework: UK SECR + CDP + SBTi tracking
Annual consumption: 2,500,000 kWh
On-site solar PV: 1,500,000 kWh generated, fully consumed on-site
EAC handling — what the reporter did: 1,500,000 REGOs issued by Ofgem against the on-site solar generation; reporter sold all 1,500,000 REGOs in Q1 2026 to a third party for ~£15,000 revenue
Reporter’s claimed MB inventory: on-site solar treated as zero-emission for the 1,500,000 kWh covered; grid factor applied to the residual 1,000,000 kWh purchased from the grid
Reporter’s claimed MB total: (1,500,000 × 0.0) + (1,000,000 × 0.13096) = 130.96 tCO₂e The trap pattern. Walks through what the reporter did, why the claim fails, what the correct MB figure is, and how an auditor detects the failure from the inventory output alone.
Standards Alignment
Six standards govern the MB methodology and its disclosure consequences.
| Standard | Role for the market-based method |
|---|---|
| GHG Protocol Corporate Standard + Scope 2 Guidance (2015) | Defines the dual-reporting requirement (§7.1), the eight Quality Criteria (Table 7.1), and the market-based data hierarchy (Table 6.3). The methodological foundation of every MB inventory line. |
| GHG Protocol Scope 3 Standard | Defines Cat 3 (FERA) — the home for the T&D losses companion line. Computed against LB factor only regardless of MB instrument basis; physical losses occur on the grid regardless of contract. |
| CSRD / ESRS E1 | EU mandatory dual disclosure (E1-6) with explicit residual mix factor citation requirement. Transition plan additionality narrative requirement (E1-1). Position C in the additionality debate. Prospective from FY2024 reporting. |
| SBTi Corporate Net-Zero Standard | One method, location-based or market-based, for base year and progress (V1.3.1 criterion C9), including under the Absolute Contraction Approach. RECs bought and used in the same market. V2.0 adds generator age and deliverability limits — Position B in the additionality debate. |
| UK DEFRA 2026 | UK grid factor: 0.131 kg CO₂e/kWh — used as Tier 5 fallback and as LB anchor in dual disclosure. Source for UK SECR. |
| ISO 14064-1 | Reasonable-assurance audit standard. Sets evidence retention and methodology transparency requirements that govern the audit pre-flight checklist in §13. |
What the Calculator Handles vs What You Decide
The Scope 2 Electricity Calculator automates the mechanical steps of MB calculation. This methodology page covers the upstream decisions the calculator cannot make for you.
- Tier 1 contract-specific factor input for PPA/VPPA matched portion
- Tier 3 supplier-specific factor input with audit-trail retention
- Tier 4 residual mix factor application on the unmatched portion (with audit warning where untraced premium fallback applies)
- Tier 5 LB fallback at site level when no instruments held; LB carry-forward to portfolio MB per §7.1 invariant
- Per-site EAC matching with REGO / GO / REC / I-REC / PPA instrument tagging
- Multi-site portfolio mode with up to 5 sites; per-site tier breakdown; portfolio totals carrying the §7.1 invariant
- Dual-method calculation (LB + MB) with the §7.1 invariant enforced — LB is never suppressible
- Audit mode with full calculation chain, hash for replay, JSON + CSV export with full provenance
- Tier selection per kWh — apply the highest-specificity tier for which qualifying evidence exists; never use a lower tier when higher-tier evidence is on hand
- Instrument basis — bundled REGO/GO/REC vs contracted PPA; per §5 instrument equivalence matrix
- Additionality posture — SBTi V2.0 age and deliverability limits on each instrument (Position B)
- EAC retention vs sale — for self-generation, retained EACs preserve zero-Scope-2; sold EACs require residual mix on the on-site consumption (failure mode 7.1)
- Vintage matching — issuance year of EACs must align with consumption year (failure mode 7.4)
- Cross-border claim verification — issuing-body jurisdiction vs consumption jurisdiction (failure mode 7.3)
- Residual mix override — calculator default is grid × 1.15 untraced premium; for AIB-published European jurisdictions, input the AIB residual mix value
- Framework reconciliation — single source-of-truth MB total across CDP, CSRD, and SBTi disclosures; reconcile any framework-specific commentary explicitly (failure mode 7.6)
- Source documentation — supplier disclosures, PPA contracts, EAC retirement statements with vintage, residual mix citations for audit retention
Ready to compute? Open the Scope 2 Electricity Calculator →
Audit Checklist — Market-Based Reasonable-Assurance Pre-Flight
Eight items, MB-specific (not duplicating the electricity methodology checklist which covers grid factor freshness, dual-method completeness, and T&D inclusion). Run this list before submitting any MB claim for reasonable-assurance review under ISO 14064-1 or equivalent.
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01
Instrument retirement evidence per claim. Every claimed REGO / GO / REC / I-REC traces to a registry retirement statement. Retirement vintage matches consumption year (failure mode 7.4). Sample at least 5 instruments per material EAC class. Reject any claim backed only by procurement contract without retirement confirmation.
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02
Tier selection justification per kWh. For each portion of consumption, document which tier was applied and why a higher tier was not. Tier 5 invocations require an explicit note that no Tier 1 to 4 evidence was available; Tier 4 invocations require the published residual mix citation; Tier 1 invocations require contract reference; Tier 3 requires the supplier disclosure document.
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03
Residual mix source citation with vintage. For Tier 4 applications, cite the AIB European Residual Mixes publication or the other residual mix you used, by year. Vintage must match inventory year, not publication date. Failure mode 7.2 detection — explicit citation prevents the grid-average substitution error.
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04
Cross-border claim evidence (failure mode 7.3). Where retired EACs originate from a different jurisdiction than the consumption they cover, document the geographic correspondence framework permitting the cross-border claim. AIB framework permits within EU/EEA/UK with disclosure; outside AIB, single-jurisdiction matching is the audit-grade default.
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05
Additionality posture disclosure. For SBTi-tracked reporters, the target-progress narrative states the method used and whether each instrument meets the V2.0 age and deliverability limits. For ESRS E1 reporters, the transition plan addresses Position C — what proportion of the MB claim is bundled vs contracted, and how that ratio is shifting.
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06
Version history restatement trigger check. If using a baseline year before January 2015, restate to post-2015 dual-method basis (per Table 9.1). If the 2026 GHG Protocol revision finalises during the reporting cycle, monitor for restatement requirements per the consultation outcome.
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07
Sold-EAC reconciliation (failure mode 7.1). For any on-site renewable generation, reconcile EAC issuance volume against retirement volume in the reporter’s own registry account. Any EAC issued from on-site generation that does not appear in the reporter’s retirement statement was sold; the corresponding consumption uses residual mix, not zero-emission claim. This is the highest-frequency MB failure in production disclosures.
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08
Cross-framework reconciliation (failure mode 7.6). The MB total disclosed to CDP, CSRD, and SBTi traces to a single source-of-truth calculation. Framework-specific commentary explains any narrative-level adjustment (e.g. an SBTi target tracked on the location-based method) without altering the inventory total. Stakeholders comparing across filings find no unexplained divergence.
Methodology Metadata — for GHG Inventory Documentation
Copy verbatim into your GHG inventory methodology statement for ISO 14064-1 transparency compliance. Adjust the tier, instrument, and framework lines to match your inventory choices.
29.8) note the basis distinction in the methodology statement.
Frequently Asked Questions
This is the instrument equivalence problem of §2 in operational form. The arithmetic equivalence is real — at zero supplier or contract factor, both produce the same per-kWh inventory contribution. The disclosure equivalence is fictional. Three reasons it matters: (1) SBTi Corporate Net-Zero Standard V2.0 limits instruments by generator age and deliverability under Position B, so a certificate that counts in your inventory may not support a V2.0 target; (2) CSRD ESRS E1 transition plan narrative under Position C requires you to disclose your bundled-vs-contracted mix, and stakeholders read this; (3) audit risk profile differs — bundled REGOs from existing assets carry medium audit risk under reasonable assurance review, contracted new-build PPAs carry low audit risk. Reporters who don’t differentiate face stakeholder questions when their CDP and SBTi totals diverge — failure mode 7.6.
Tier 3 is the supplier’s matching at portfolio level; Tier 1 is the reporter’s matching at contract level. Practical case: you take supply from a UK utility on their “Green Origin” tariff. The utility sources REGOs across its portfolio, retires them to back the tariff, and publishes a tariff-specific factor in its annual disclosure (say 0.043 kg CO₂e/kWh as in Worked Example A). Your MB inventory uses that factor — Tier 3. Alternative case: you sign a 10-year virtual PPA with a specific solar developer for 50 GWh/year of contracted output and the associated EACs. You retire those EACs in your own registry account against your own consumption. Your MB inventory treats the matched portion at zero (or whatever the contract factor is) — Tier 1. The legal distinction: Tier 3 you bought a tariff product; Tier 1 you bought a contractual claim over named generation. The audit distinction: Tier 3 evidence is the supplier disclosure document; Tier 1 evidence is the contract plus the registry retirement statement under your account.
Conditionally yes within established cross-border frameworks; typically no outside them. GHG Protocol Quality Criterion 5 requires the instrument to come from the same market as the consumption it covers. Within the AIB framework (EU/EEA/UK), cross-border GO and REGO retirement is permitted with explicit disclosure of the issuing-body jurisdiction in the disclosure narrative — a French operation can retire German GOs, a UK operation can retire Norwegian REGOs, both with disclosure. Outside AIB, single-jurisdiction matching is the audit-grade default — retiring I-RECs from Brazil against EU operations triggers failure mode 7.3 (cross-border instrument mismatch) and is rejected at reasonable-assurance review. Within the US, REC tracking systems (WREGIS, PJM-EIS GATS, etc.) are NERC-subregion-aware; cross-subregion retirement is permitted with disclosure but increasingly scrutinised. Practical rule: match EAC sourcing to consumption jurisdiction within established cross-border frameworks; outside them, stay within jurisdiction.
The two co-exist on different layers. Your CDP C6.3 submission carries the inventory MB total computed under GHG Protocol Position A. Your SBTi target progress uses whichever single method you chose for the target, location-based or market-based. Under V1.3.1, certificates bought and used in the same market count toward a market-based target with no separate additionality test. From February 2027, a V2.0 target may exclude instruments from generators over 15 years old or outside the activity pool. The correct disclosure pattern: report the inventory total once, consistently across CDP and CSRD, and state the target method and any excluded instruments in the target progress narrative. Failure mode 7.6 surfaces when the two are not reconciled in the disclosure narrative; analysts compare and find a gap they cannot explain.
The residual mix is the emission factor for the portion of grid electricity not claimed by any contractual instrument — the grid average less the generation already retired via EACs by other reporters. It almost always exceeds the location-based factor in jurisdictions with material EAC retirement, because the renewable share of the grid has been contractually allocated to other reporters and what remains is dirtier than the grid average. The UK 2025 AIB residual mix is approximately 0.28064 kg CO₂e/kWh — over 2.1× the LB grid factor of 0.131 kg CO₂e/kWh — because European EAC retirement volumes are large relative to the underlying grid. The structural detection signature in failure mode 7.1: when the corrected MB total exceeds the LB total, the cause is residual mix application, and that almost always traces to a sold-EAC scenario on a site that should have retained its instruments. Worked Example C demonstrates: corrected MB of 701.60 tCO₂e exceeds LB of 327.40 tCO₂e because residual (0.28064) exceeds grid average (0.13096). For the underlying mathematics, see the residual mix section in the electricity methodology.
Tier-specific. For Tier 3 supplier-specific: the supplier’s annual fuel-mix or emissions disclosure document for the reporting year, citing the specific tariff under which supply was taken, with cross-reference to the regulator filing where applicable (Ofgem Fuel Mix Disclosure for the UK, equivalent regulated disclosures in EU member states). For Tier 1 contract-specific: the executed contract or PPA term sheet identifying the generation asset, the contracted volume, and the EAC handling; plus the registry retirement statement under the reporter’s own account covering the reporting year specifically; for VPPAs, the financial settlement evidence plus the EAC delivery statement. For Tier 4 residual: the AIB European Residual Mixes publication citation or the other residual mix you used, by vintage year matching the inventory year. For self-generation: registry retirement statements under the reporter’s own account showing all on-site-generated EACs were retained (not sold to third parties — the failure mode 7.1 check). For cross-framework reconciliation (failure mode 7.6): a single source-of-truth MB calculation document with framework-specific commentary appended for CDP, CSRD, and SBTi. Retention period per ISO 14064-1: minimum five years for most organisations.
You can claim the on-site generation as not-imported electricity — your Scope 2 boundary covers only purchased electricity, and self-generated kWh consumed on-site never enters Scope 2 in the first place. But you cannot also claim the renewable attribute as MB zero-emission once you have sold the REGOs. Per §3 contractual claim architecture, energy and attribute are severable. You retained the energy (used on-site) and you sold the attribute (REGOs went to the buyer). The buyer now has the renewable claim against your generation. Your remaining Scope 2 inventory is the grid-imported kWh, plus the on-site consumption must use residual mix factor (because no instruments are retained against it). Worked Example C demonstrates the failure mode 7.1 trap: the reporter tried to claim both on-site reduction and EAC sale revenue. The correct posture is binary — either retain all on-site EACs and claim zero-Scope-2 on the on-site consumption, or sell the EACs and apply residual mix to the on-site consumption. Mixing the two double-counts the renewable benefit between your inventory and the buyer’s inventory, and it is the highest-frequency MB failure auditors detect.
Position monitoring is the current posture — the revision is in consultation, not finalised. Restatement requirements depend on the final scope. Areas of likely revision include hourly carbon-free energy matching (a structural shift from annualised matching that would not necessarily restate prior years but would change forward methodology), residual mix governance (potentially requiring vintage clarifications), and Quality Criteria refinement (potentially affecting bundled-instrument acceptability). The 2015 publication is the analogue — that release required restatement only for trend baselines extending pre-2015 (Table 9.1, restatement column). The 2023 ESRS E1 release required additional disclosure prospectively but not restatement. Reporters with active SBTi targets should monitor the consultation outcome closely; reporters with stable post-2015 baselines are unlikely to face restatement requirements. The changelog will track the revision through publication.
Calculator
Apply the five-tier emission factor hierarchy with audit-grade output, dual-method (LB + MB) display under the §7.1 invariant, multi-site portfolio mode with per-site tier breakdown, EAC instrument tagging across REGO / GO / REC / I-REC / PPA, residual mix application with audit warnings on T-0 fallback, and JSON + CSV export with full provenance: Open the Scope 2 Electricity Calculator →