Summary: This is an extract of Chapter 8. This chapter describes additional information that companies should disclose about the features and policy context of their energy purchases. This disclosure can improve transparency and inform stakeholders.
8.1 Instrument feature disclosure
Markets currently differ as to what types of energy generation facilities produce instruments that are recognized in the market-based method for corporate GHG inventories. Different programs establish their own eligibility criteria that determine what energy generation facilities can produce certificates that are recognized in the program. (See Chapter 10 for background on these differences).
This variation can make it difficult to compare and understand the procurement choices a company has made in different markets. However, when companies disclose information about the energy generation facilities and policy context reflected in their contractual instruments, company decision makers and stakeholders can get a clearer picture about how well the purchase aligns with other company goals. In particular, stakeholders evaluating a company’s contribution to mitigating global emissions may be interested in how a company is driving change in supply.
If information on these features or policy context is not made available on or with the certificate, companies can ask the certification program, tracking system, or supplier for further information. Lacking other information, a company may disclose the overall criteria identified by the certificate program (e.g. Green-e Energy certified RECs are from facilities installed in the last fifteen years on a rolling basis).
8.1.1 Instrument feature disclosure formats
Companies can disclose features about their contractual instruments in a variety of formats depending on the intended audience, communication channel (summary report vs. full extended report), etc. Companies may find a checklist approach may help maintain clarity on the features associated with each contractual instrument, depending on the number of energy-consuming facilities and different instruments in the inventory. See Table 8.1 for a list of these features and policy contexts. In cases where companies have undertaken strategic or iconic projects, a more narrative format can be useful to highlight the project’s features in the context of a larger history.
8.2 Reporting on the relationship between voluntary purchases and regulatory policies
This guidance does not require contractual instruments claimed in scope 2 to be “in addition to,” or independent from, regulatory policies such as subsidies, tax exemptions, or supplier quotas. Due to the design of renewable energy production targets, achieving “regulatory surplus” with voluntary purchases may not always be possible.
For transparency, companies should disclose the relationships between instruments claimed in scope 2 and regulatory policies, as part of the disclosure of overall instrument features and policy context to improve transparency and stakeholder understanding of the voluntary purchase. Companies should also disclose additional certificates or other instrument retirement performed in conjunction with their voluntary claim. These relationships and reporting options are elaborated below.
8.2.1 Relationship to supplier quotas
Where relevant, companies should state the relationship between the energy claimed in the market-based method and any compliance instruments used for supplier quota regulations. Six example relationships can be found in Table 8.2.
8.2.2 Relationship to subsidy receipt
In some countries, renewable energy projects that receive a public subsidy such as a feed-in-tariff (FiT) must have the certificate from that project retired or canceled, preventing any individual consumer claim. For instance, in Germany if a generation facility receives subsidies, then all generation attributes must be either canceled or retired on behalf of all German consumers under the rationale these consumers have paid for the energy through taxes, and should therefore collectively own the attributes. (This is in contrast to other European member states, which allow for individual consumer attribute ownership in addition to national subsidies.) In Japan, once renewable electricity that receives a FiT is sold to utilities, voluntary renewable energy certificates cannot be issued. Accordingly, for the purpose of achieving regional fairness, the value of zero emissions energy generated from FiT-supported renewable electricity is allocated to each utility in accordance with sales amounts because FiT represents a public subsidy.
In practice, this leaves subsidized energy a “public good” whose attributes are included in a system mix used for supplier reporting. Reporting options: In jurisdictions where energy supported by recent or substantial renewable energy production subsidies is not excluded from voluntary programs or claims, companies should disclose subsidy receipt (available on GO).
8.1.3 Relationship to emissions trading programs
In emissions-capped power programs such as the European Emissions Trading Scheme, low-carbon energy generation is incentivized through creating a limit (cap) on fossil-fuel emissions. But all energy attribute certificates, including voluntary energy attribute certificates and other contractual instruments can still convey emission rate claims under an emissions cap (e.g., renewable energy still produces zero emissions/MWh at the point of generation). The presence of a cap does not directly impact or prevent market-based accounting based on contractual instruments.
However, because the total system’s emissions have been predetermined by the cap, these actions may simply “free up” allowances for other emitters to acquire, resulting in no net global GHG reductions. This means consumers cannot claim that the generation purchased resulted in global emission reductions on the grid; only by affecting the allowance cap by retiring or reducing available allowances would electricity consumers be able to support that claim. Voluntary low-carbon energy purchases (as well as other actions such as efficiency upgrades or energy conservation) without allowance retirement could be seen as an essential and expected means of contributing to meeting the system-wide cap, or as “subsidizing” the overall sector’s costs for meeting the cap.
Allowance set-asides.
Many states participating in the U.S. Regional Greenhouse Gas Initiative (RGGI) and the California cap-and-trade program have created an allowance set-aside program. These programs designate that a portion of total emission allowances available in a given compliance period be set aside and retired on behalf of voluntary REC purchases. This combined REC purchase and allowance retirement is designed to preserve or strengthen the global carbon benefits and impacts for voluntary renewable energy purchases. In theory, allowances could be retired by any entity trying to demonstrate environmental commitment, as a reduction in available allowances for emitting entities can create scarcity (and theoretically, behavior change) in the marketplace. Retiring allowances effectively lowers the cap.
Reporting options. Companies claiming contractual instruments in an emissions-capped power sector should disclose whether an allowance set-aside program is in place, and whether any allowances have been retired along with the voluntary certificates. The tons of GHG emissions represented in any retired allowances should be reported separately from the scopes.
Caveats.
This guidance does not recommend treating allowances retired as part of a voluntary renewable energy set-aside as though they were offsets. Conceptually, allowances could be seen to function as offsets in that they represent tons of CO2e that were avoided compared to what would have happened without the purchase and retirement of the allowance. While the reference case in this analysis would be the emissions cap for the sector, it has not always been clear that this cap inherently represents “what would have happened” and that the allowance retirement is therefore additional.
On their own, most emission caps are intended to reduce emissions compared to what would have been occurring in the sector. But in oversupplied allowance markets, where the cap level closely follows or even exceeds what would have been occurring anyway (e.g. during a period of economic downturn), the value of retiring an allowance might be minimized. Further, if allowance retirement becomes common practice and significantly increases the price of allowances, cost containment measures in cap-and-trade policies may be triggered so that regulators increase the total volume of available
8.1.4 Relationship to offset credits
Offsets generated from renewable energy facilities remain a popular project type in offset schemes such as the Clean Development Mechanism (CDM), as well as voluntary standards. These programs are designed to provide a revenue stream that enables a project to be built that—in the absence of the offset sales—would be unfeasible. The offset represents a quantity of global GHG emissions reduced or avoided by the project compared to a baseline scenario of what emissions would have occurred in the absence of the offset-funded project.
Distinguishing attributes and claims. Offsets, and their global avoided emissions claim, represent a different instrument and claim from the energy attributes associated with energy production.2 Offsets convey tons of avoided CO2 using project-level accounting, but they do not convey information about direct energy generation emissions occurring at the point of production, like contractual instruments do (see Box 4.3). An offset credit does not confer any claims about the use of electricity attributes applicable to scope 2. For example, to distinguish avoided emissions and emission rates, a natural gas facility newly established in a largely coal-based grid will avoid operating margin emissions as fossil fuel plants with higher operating costs are backed down. But the natural gas plant still emits at a fixed rate (emissions/MWh), which consumers of that energy can document in scope 2.
Coexistence of offsets and scope 2 accounting. Unless otherwise adjusted by local rules, renewable energy generation facilities producing and selling offsets will inherently still provide energy attribute information— directly and indirectly—to other entities in the local energy supply system, including energy consumers reporting scope 2 emissions. For instance, the energy output from generation facilities producing offsets would still be subject to energy supply contracts between generators and suppliers, and still support the local grid’s operation. This means that the zero emission rate from the generation facility will likely be reflected in several emission factors:
- Grid average emission factors (location-based)
- Supplier-specific emission factors (market-based)
- Any PPAs between the generator and consumer of the energy (market-based)
The contractual information such as PPAs and supplier- specific emission factors may meet the Scope 2 Quality Criteria and qualify as conveyers of energy generation emission rates under the market-based method. This can provide accurate scope 2 accounting independent of the fact that certain facilities associated with those contracts will have also produced offsets (reflecting the impact of that generation on the rest of the grid). Therefore, the zero emission rate from the project will likely be reflected in the local grid’s data for both the location-based and market-based method for scope 2, as illustrated in Figure 8.1. However, in most industrialized energy markets, a given MWh of renewable energy generation can either produce energy attribute certificates or an offset credit (if certain criteria such as additionality are met), but could not produce both.
Reporting options: Companies should disclose whether their contractual instrument used in a market-based method (such as a supplier-specific emission rate or PPA) is generated from, or includes, the energy output of a facility that also produces GHG offsets. This may be most relevant in non-Annex I countries generating CDM offsets.
In turn, following the Corporate Standard, companies purchasing and claiming offsets should document these purchases outside of the scopes, ensuring that the offset meets offset quality criteria.
Caveats: The coexistence of offsets does not inherently prevent electricity suppliers or companies from reflecting the zero emissions attributes in their scope 2 reported totals. However, local or international regulation may preclude accounting for these emissions, either by:
- Adjusting a grid-average emissions factor to “add back in” the sold offset to the total emissions produced in the region. This increases the GHG intensity of the grid- average emission rate, effectively reflecting the business- as-usual (BAU) scenario of the offset.
- Requiring provisions in energy purchase contracts that the attributes associated with the energy generation, while not contained in the offset, should be retired from usage so that no consumer can use contractual instruments to make market-based scope 2 claims.
Historically, voluntary consumer green power purchasing programs have not been implemented in emerging economies generating offsets. This may change over time as local consumers demand low-carbon energy options from their suppliers. (Generally, offsets from the power sector are not possible where the emission caps or other
significant low-carbon policies impact the sector.) Where voluntary green power consumer programs coexist with offset issuance, the offset additionality criteria requires that the offset be the decisive reason a project was developed.
