Disclosing Scope 2 Emissions under the GHG Protocol - Recommended Disclosures

Summary: This is an extract of Chapter 7. This chapter identifies all the new accounting and reporting requirements introduced by this Guidance. Conformance with this Guidance is required in order to prepare an inventory in conformance with the Corporate Standard.

This Guidance provides a new set of requirements applied to the Corporate Standard in calculating and reporting scope 2 emissions. Therefore, conformance with this Guidance is required in order to prepare an inventory in conformance with the Corporate Standard. In addition to all existing Corporate Standard accounting and reporting requirements (see Chapter 9 of the Corporate Standard), companies shall calculate and report scope 2 in the following ways:

7.1 Required information for scope 2

For companies with operations only in markets that do not provide product or supplier-specific data or other contractual instruments:

For companies with any operations in markets providing product or supplier- specific data in the form of contractual instruments (Markets are increasingly developing and refining purchasing options, and the list is not exhaustive. Currently this includes the EU Economic Area, the U.S., Australia, most Latin American countries, Japan, and India, among others.)

method applies and some where it does not. Companies shall account for and report all operations’ scope 2 emissions according to both methods.

Scope 2 Quality Criteria

Companies shall ensure that any contractual instruments used in the market-based method total meet the Scope 2 Quality Criteria specified in Table 7.1. If instruments do not meet the Criteria, then other data (listed in Table 6.3) shall be used as an alternative in the market-based method total. In this way, all companies required to report according to the market-based method will have some type of data option.

supplier label, green power program, etc. An attestation form may be used to describe the chain of custody of purchased certificates or other contractual instruments.

Inventory totals. For companies adding together scope 1 and scope 2 for a final inventory total, companies may either report two corporate inventory totals (one reflecting each scope 2 method), or may report a single corporate inventory total reflecting one of the scope 2 methods.

Methodology disclosure. Companies shall disclose methods used for scope 2 accounting. For the market based method, companies shall disclose the category or categories of instruments from which the emission factors were derived, where possible specifying the energy generation technologies.

Base-year information. Companies shall disclose the year chosen as the base year; the method used to calculate the base year’s scope 2 emissions; whether historic location based data is used as a proxy for a market-based method; and the context for any significant emission changes that trigger base-year emissions recalculation (acquisitions/ divestitures, outsourcing/insourcing, changes in reporting boundaries or calculation methodologies, etc.)

Disclose basis for goal setting. If a company sets a corporate inventory reduction goal and/or a scope 2-specific reduction goal, the company shall clarify whether the goal is based on the location-based method total or market based method total.

7.2 Recommended disclosure

Annual electricity consumption. Companies should report total electricity, steam, heat, and cooling per reporting period separately from the scopes totals (in kWh, MWh, BTU, etc.), which should include all scope 2 activity data as well as the quantity of energy consumed from owned/ operated installations (which may be only reported in scope 1 and not in scope 2.)

Biogenic emissions. Companies should separately report the biogenic CO2 emissions from electricity use (e.g. from biomass combustion in the electricity value chain) separately from the scopes, while any CH4 and N2O emissions should be reported in scope 2.

Other instrument retirement. Companies should disclose additional certificate or other instrument retirement performed in conjunction with their voluntary claim, such as with certificate multipliers or any pairing required by regulatory policy.

Basis for upstream scope 3. The reporting entity should identify which methodology has been used to calculate and report scope 3, category 3—upstream energy emissions not recorded in scope 1 and 2, scope 3.

Instrument features. Where relevant, companies should disclose key features associated with their contractual instruments claimed, including any instrument certification labels that entail their own set of eligibility criteria, as well as characteristics of the energy generation facility itself and the policy context of the instrument. These features are elaborated in Chapter 8.

Role of corporate procurement in driving new projects. Where relevant, companies should elaborate in narrative disclosure how any of the contractual instruments claimed in the market-based method reflect a substantive contribution by the company in helping implement new low- carbon projects.

7.3 Optional information

Scope 2 totals disaggregated by country. This can improve transparency on where market-based method totals differ from location-based.

Avoided emissions estimation. Consistent with Chapter 8 of the Corporate Standard, companies may separately report an estimation of GHG emissions avoided from a project or action (also see Section 6.9). This quantification should be based on project-level accounting, with methodologies and assumptions documented (including to what the reduction is being compared). See the GHG Project Protocol and GHG Protocol Guidelines for Grid- Connected Electricity Projects for example methodologies.

Advanced grid study estimations. Where advanced studies (or real-time information) are available, companies may report scope 2 estimations separately as a comparison to location-based grid average estimations, and companies can document where this data specifically informed efficiency decision making or time-of-day operations. Because these studies or analyses may be more difficult to use widely across facilities or to standardize/aggregate consistently without double counting, companies should ensure that any data used for this purpose has addressed data sourcing and boundaries consistent with the location- based method.

Scope 2 results calculated by other methods. If companies are subject to mandatory corporate reporting requirements for facilities in a particular region/nation that specify methodologies other than the two required for dual reporting, these companies may report these results separately from the scopes.

Disclose purchases that did not meet Scope 2 Quality Criteria. If a reporting entity’s energy purchases did not meet all Scope 2 Quality Criteria, the entity may note this separately. This note should detail which Criteria have been met, with details of why the remaining Criteria have not. This will provide external stakeholders with the information they require, and allow the reporting entity to disclose the efforts made to adhere to the guidance. (As noted in Chapter 6, location-based method data will be used as proxy emission factors in the market-based method total.)

See the Corporate Standard Chapter 9 for more information about optional information and how to use ratio indicators and other performance metrics in reporting.

7.4 Dual reporting

Dual reporting allows companies to compare their individual purchasing decisions to the overall GHG-intensity of the grids on which they operate. In addition, reporting two separate scope 2 figures using two different methods provides several benefits:

This guidance’s framework addresses and reduces double counting between scope 2 inventories when using the same accounting method, improving the accuracy of reported results and ensuring clear performance tracking toward goals.

The UK represents an example of the differing demands of the various stakeholders, where organizations (especially those trading internationally) have complex demands from their stakeholders. The carbon inventory is often reviewed by investors based in the United States, where there is an expectation to report using the market- based approach. However, the prevailing guidance from the UK government is to report using the locational-based approach, in part due to concerns regarding subsidy levels for renewables and double counting concerns. For these organizations, dual reporting provides disclosure in a way that allows all stakeholders to be satisfied.

7.4.1 Other methods

Some jurisdictions may recommend methods other than the location-based or market-based method as the basis for its consumer claims and scope 2 accounting, in order to achieve specific policy objectives. For instance, Ademe1 in France has calculated different grid GHG emission rates according to different end uses by consumers. This represents a different emissions allocation approach than the location-based method presented in this guidance, although it is derived from it. It recommends companies reporting to Ademe apply these end-use factors to the different types of energy end uses, in order to better estimate the average GHG impact of specific consumption activities.

Companies required by regulation to use a method other than those listed in this guidance should do so for those required reports. To maintain consistency with the GHG Protocol Corporate Standard and this Scope 2 Guidance, companies may additionally and separately report any scope 2 totals calculated for other mandatory reporting rules applying to that region/nation’s facilities.

7.4.2 Gross/net reporting

The two method totals (location-based and market-based) should not be viewed as “gross/net,” since a net calculation typically implies that external reductions such as offsets have been applied to the inventory. While many contractual instruments in the market-based method represent a zero emission rate from renewable energy and generally serve to lower the GHG intensity of the reporter’s electricity use, the market-based method should also include other contractual instruments representing fossil fuel or mixed-resource emission factors as well. The method is designed to reflect a range of instruments that together allocate overall emissions across the grid. For instance, a supplier-specific emission rate that includes a mix of generation technologies also is a valid market-based method emission factor.

However, companies can report avoided emissions estimations from generation separately from the scopes and indicate if these have been used in program-specific gross/net reporting (such as Defra Corporate guidelines2).

7.5 Additional guidance on Scope 2 Quality Criteria

The environmental integrity of the market-based method depends on ensuring that contractual instruments reliably and uniquely convey GHG emission rate claims to

consumers. Without this, a resulting market-based scope 2 total lacks the accuracy and consistency necessary to drive corporate energy procurement decisions. In addition, the lack of a reliable system for tracking or assuring claims poses risks of inaccurate consumer claims regarding a product’s actual attributes, and weakens the ability for consumer decisions to influence market supply.

Therefore, this guidance identifies a set of minimum criteria that relate to the integrity of the contractual instruments as reliable conveyers of GHG emissions rate information and claims, as well as the prevention of double counting. They represent the minimum features necessary to implement a market-based method of scope 2 GHG accounting. Programs or jurisdictions may have additional requirements that reporting entities should consult and follow.

Criteria 1. Conveying GHG emission rate claims. Many instruments already include specific language about the ownership or ability to claim specific attributes about the product (energy) being generated. In the U.S., most states (and the Green-e Energy National Standard) define RECs as conveying “all environmental attributes” associated with the MWh of energy generation. This type of claim is considered “fully aggregated,” meaning that no other instrument can be generated from that MWh which conveys consumer claims regarding any of the environmental attributes of the energy. (In specific cases of multipliers or issuance of multiple instruments from the same MWh, then all instruments shall be retired for a full claim on that MWh.) Tracking systems themselves support only fully aggregated certificates.

In some markets it may be possible for attribute claims about energy generation to be separated out explicitly into different certificates that could be used for different purposes. This guidance does not address program design elements in markets with multiple certificates, but requires that only one instrument (or discrete set of instruments applied all at once) convey attribute claims about the energy type and its GHG emission rate.

If certificates do not specify attributes: Certificates that do not currently specify what, if any, energy attribute claims are conveyed, may still convey a claim implicitly through proving the second point: that no consumer is claiming the same energy generation attributes.

Evidence of this may be achieved through attestations from each owner in the chain of custody or equivalent procedures providing the same information.

If the attribute emission rate itself is not specified and the technology is not zero emissions, the reporting organization should seek from the generating entity a specific emission rate from that generation facility. Otherwise, a default factor from IPCC or other government publications may be used and disclosed.

Biofuel generation facilities producing certificates should specify the CO2, CH4, and N2O emissions produced at the point of generation. The scope 2 reporter reports the CH4 and N2O emissions in scope 2, while the CO2 from biofuel is reported separately from the scopes.

Criteria 2. Unique claims. If other instruments exist that can be used for attribute claims by other electricity consumers, companies must ensure that the one being used by the reporting entity for a GHG emission rate claim is the only and sole one that does so. Where multiple instruments carry the GHG emission rate attribute claim, some jurisdictions or programs may require acquisition and “pairing” of the multiple certificates to support a voluntary consumer GHG emission rate claim.

Companies should check with their electricity supplier or relevant policy-making bodies to ensure that the certificates are claimed, paired, or retired in compliance with applicable jurisdictional or program requirements.

The underlying electricity (or megawatt-hour) minus the instrument, sometimes called “null power,” shall also not reflect the same GHG emission rate, but should be assigned residual mix emissions for the purpose of delivery and/or use claims in the market-based method.

In some cases, ensuring unique GHG emission rate claims may require arbitration regarding the validity and enforceability of a claim where multiple instruments exist and remain unclear on attribute claims.

Criteria 3. Retirement for claims. Ensuring that instruments are retired, redeemed, or claimed to support a consumer claim can be done through a tracking system, an audit of contracts, third-party certification, or may be handled automatically through other disclosure registries, systems, or mechanisms. These practices help guarantee that only consumers make a claim, even as

an instrument may change hands through trading.

Criteria 4. Vintage. Vintage reflects the date of energy generation from which the contractual instrument is derived. This is different from the age of the facility. In order to ensure temporal accuracy of scope 2 calculations, this criteria seeks to ensure that the generation on which the emission factors are based occurs close in time to the reporting period for which the certificates (or emissions) are claimed. This timing should be consistent with existing standards for the market where the contractual instruments exist. Contractual instruments should clearly display when the underlying electricity was generated.

Criteria 5. Market boundaries. The market boundary criteria address the geographic boundary from which certificates can be purchased and claimed for a given operation’s scope 2 accounting and reporting.

Distinguishing other relevant electricity boundaries: The market for purchasing and selling electricity is typically a regional transmission organization, power pool, or balancing area, with exports and imports often broadening these markets. By definition, certificates are separated from underlying electricity flows, and markets for unbundled certificates have often been less constrained than those for electricity itself. This larger market boundary for certificate use promotes broader areas of consumer choice and the building of renewable energy resources in the most economically viable locations.

To determine market boundary: Companies should check whether the regulatory authorities and/or certification/issuing bodies responsible for certificates have established the boundaries in which certificates may be traded and redeemed, retired or canceled, and should follow these market boundaries.

If the market boundary is not specified or not clear: Markets for certificates are typically determined by political or regulatory boundaries rather than just physical grid interconnection. This means market boundaries can be limited to a single country or group of countries that recognize each other’s certificates as fungible and available to any consumers located therein. The United States, for example—despite differences in state law, local regulatory policy, and variation in physical interconnection within these regions—operates under broad federal laws and regulations, and therefore has constituted a single market for use of certificates. The EU represents a multi-country market united by a set of common market rules and a regional connection.

Where multiple countries or jurisdictions form a single market, a consistent means of tracking and retiring certificates, and calculating a residual mix, needs to be present in order to prevent double counting of GHG emission rates among electricity consumers. Accurate residual mixes should take into account the energy and emission mixes of all geopolitical entities engaged in trading certificates.

Additional geographic sourcing considerations: In addition, if not already specified by regulation or program, contractual instruments should be sourced from regions reasonably linked to the reporting entity’s electricity consumption.

These regions may grow over time as more interconnections and larger balancing areas are formed to improve grid reliability and integrate intermittent renewables.

Criteria 6. Supplier or utility-specific emission factors. As part of the calculation, the utility or supplier should disclose whether and how certificates are used in the emission factor calculation, unless there is third- party certification of the utility product. The utility

or supplier-specific emission factor may be for:

The supplier-specific emission factor should be disclosed (preferably publicly) according to best available information. Where possible, this should also follow best practice methods, such as The Climate Registry Electric Power Sector Protocol.

Criteria 7. Direct contracts or purchasing. In the absence of energy attribute certificates, the contract and claim associated with it should be verified by a third party to convey a unique or sole ownership right to claim a GHG emission rate.

Criteria 8. Residual mix. To ensure unique claims by all electricity users, an adjusted, residual mix characterizing the GHG intensity of unclaimed or publicly shared electricity is necessary. This residual mix should be based on combining national or subnational energy and emissions production data with contractual instrument claims. If a residual mix is not currently available, companies shall disclose that an adjusted emissions factor is not available or has not been estimated to account for voluntary purchases and this may result in double counting between electricity consumers.

Reporters may provide other information about the magnitude of this error, where it is available and where it puts the scale of the residual mix adjustment into a context of other sources of error in grid emission factor calculation.