GHG Protocol Corporate Standard
Standard 4 Setting Operational Boundaries
After a company has determined its organizational boundaries in terms of the operations that it owns or controls, it then sets its operational boundaries. This involves identifying emissions associated with its operations, categorizing them as direct and indirect emissions, and choosing the scope of accounting and reporting for indirect emissions.
For effective and innovative GHG management, setting operational boundaries that are comprehensive with respect to direct and indirect emissions will help a company better manage the full spectrum of GHG risks and opportunities that exist along its value chain.
Direct1 GHG emissions are emissions from sources that are owned or controlled by the company.
Indirect2 GHG emissions are emissions that are a consequence of the activities of the company but occur at sources owned or controlled by another company. What is classified as direct and indirect emissions is dependent on the consolidation approach (equity share or control) selected for setting the organizational boundary (see Standard 3 Setting Organizational Boundaries). The figure below shows the relationship between the organizational and operational boundaries of a company.
Introducing the concept of “ scope”
To help delineate direct and indirect emission sources, improve transparency, and provide utility for different types of organizations and different types of climate policies and business goals, three “scopes” (scope 1, scope 2, and scope 3) are defined for GHG accounting and reporting purposes. Scopes 1 and 2 are carefully defined in this standard to ensure that two or more companies will not account for emissions in the same scope. This makes the scopes amenable for use in GHG programs where double counting matters.
Companies shall separately account for and report on scopes 1 and 2 at a minimum.
Scope 1: Direct GHG emissions
Direct GHG emissions occur from sources that are owned or controlled by the company, for example, emissions from combustion in owned or controlled boilers, furnaces, vehicles, etc.; emissions from chemical production in owned or controlled process equipment.
Direct CO2 emissions from the combustion of biomass shall not be included in scope 1 but reported separately (see Standard 9 Reporting GHG Emissions).
GHG emissions not covered by the Kyoto Protocol, e.g. CFCs, NOx, etc. shall not be included in scope 1 but may be reported separately (see Standard 9 Reporting GHG Emissions).
Scope 2: Electricity indirect GHG emissions
Scope 2 accounts for GHG emissions from the generation of purchased electricity3 consumed by the company.
Purchased electricity is defined as electricity that is purchased or otherwise brought into the organizational boundary of the company. Scope 2 emissions physically occur at the facility where electricity is generated.
Scope 3: Other indirect GHG emissions
Scope 3 is an optional reporting category that allows for the treatment of all other indirect emissions. Scope 3 emissions are a consequence of the activities of the company, but occur from sources not owned or controlled by the company. Some examples of scope 3 activities are extraction and production of purchased materials; transportation of purchased fuels; and use of sold products and services.
Guidance 4 Setting Operational Boundaries
An operational boundary defines the scope of direct and indirect emissions for operations that fall within a company’s established organizational boundary. The operational boundary (scope 1, scope 2, scope 3) is decided at the corporate level after setting the organizational boundary. The selected operational boundary is then uniformly applied to identify and categorize direct and indirect emissions at each operational level (see Box 2). The established organizational and operational boundaries together constitute a company’s inventory boundary.
B O X 2 Organizational and operational boundaries |
Organization X is a parent company that has full ownership and financial control of operations A and B, but only a 30% non-operated interest and no financial control in operation C. Setting Organizational Boundary: X would decide whether to account for GHG emissions by equity share or financial control. If the choice is equity share, X would include A and B, as well as 30% of C’s emissions. If the approach chosen is financial control, X would count only A and B’s emissions as relevant and subject to consolidation. Once this has been decided, the organizational boundary has been defined. Setting Operational Boundary: Once the organizational boundary is set, X then needs to decide, on the basis of its business goals, whether to account only for scope 1 and scope 2, or whether to include relevant scope 3 categories for its operations. Operations A, B and C (if the equity approach is selected) account for the GHG emissions in the scopes chosen by X, i.e., they apply the corporate policy in drawing up their operational boundaries. |
Accounting and reporting on scopes
Companies account for and report emissions from scope 1 and 2 separately. Companies may further subdivide emissions data within scopes where this aids transparency or facilitates comparability over time.
For example, they may subdivide data by business unit/facility, country, source type (stationary combustion, process, fugitive, etc.), and activity type (production of electricity, consumption of electricity, generation or purchased electricity that is sold to end users, etc.).
In addition to the six Kyoto gases, companies may also provide emissions data for other GHGs (e.g., Montreal Protocol gases) to give context to changes in emission levels of Kyoto Protocol gases. Switching from a CFC to HFC, for example, will increase emissions of Kyoto Protocol gases. Information on emissions of GHGs other than the six Kyoto gases may be reported separately from the scopes in a GHG public report.
Together the three scopes provide a comprehensive accounting framework for managing and reducing direct and indirect emissions. The figure below provides an overview of the relationship between the scopes and the activities that generate direct and indirect emissions along a company’s value chain.
A company can benefit from efficiency gains throughout the value chain. Even without any policy drivers, accounting for GHG emissions along the value chain may reveal potential for greater efficiency and lower costs (e.g., the use of fly ash as a clinker substitute in the manufacture of cement that reduces downstream emissions from processing of waste fly ash, and upstream emissions from producing clinker).
Even if such “win-win” options are not available, indirect emissions reductions may still be more cost effective to accomplish than scope 1 reductions. Thus accounting for indirect emissions can help identify where to allocate limited resources in a way that maximizes GHG reduction and return on investment.
Appendix D lists GHG sources and activities along the value chain by scopes for various industry sectors.
Scope 1: Direct GHG emissions
Companies report GHG emissions from sources they own or control as scope 1. Direct GHG emissions are principally the result of the following types of activities undertaken by the company:
- Generation of electricity, heat, or steam. These emissions result from combustion of fuels in stationary sources, e.g., boilers, furnaces, turbines
- Physical or chemical processing4. Most of these emissions result from manufacture or processing of chemicals and materials, e.g., cement, aluminium, adipic acid, ammonia manufacture, and waste processing
- Transportation of materials, products, waste, and employees. These emissions result from the combustion of fuels in company owned/controlled mobile combustion sources (e.g., trucks, trains, ships, airplanes, buses, and cars)
- Fugitive emissions. These emissions result from intentional or unintentional releases, e.g., equipment leaks from joints, seals, packing, and gaskets; methane emissions from coal mines and venting; hydrofluorocarbon (HFC) emissions during the use of refrigeration and air conditioning equipment; and methane leakages from gas transport.
SALE OF OWN-GENERATED ELECTRICITY
Emissions associated with the sale of own-generated electricity to another company are not deducted/netted from scope 1. This treatment of sold electricity is consistent with how other sold GHG intensive products are accounted, e.g., emissions from the production of sold clinker by a cement company or the production of scrap steel by an iron and steel company are not subtracted from their scope 1 emissions. Emissions associated with the sale/transfer of own-generated electricity may be reported in optional information (see Standard 9 Reporting GHG Emissions).
Scope 2: Electricity indirect GHG emissions
Companies report the emissions from the generation of purchased electricity that is consumed in its owned or controlled equipment or operations as scope 2. Scope 2 emissions are a special category of indirect emissions. For many companies, purchased electricity represents one of the largest sources of GHG emissions and the most significant opportunity to reduce these emissions.
Accounting for scope 2 emissions allows companies to assess the risks and opportunities associated with changing electricity and GHG emissions costs. Another important reason for companies to track these emissions is that the information may be needed for some GHG programs.
Companies can reduce their use of electricity by investing in energy efficient technologies and energy conservation. Additionally, emerging green power markets5 provide opportunities for some companies to switch to less GHG intensive sources of electricity.
Companies can also install an efficient on site co-generation plant, particularly if it replaces the purchase of more GHG intensive electricity from the grid or electricity supplier. Reporting of scope 2 emissions allows transparent accounting of GHG emissions and reductions associated with such opportunities.
INDIRECT EMISSIONS ASSOCIATED WITH TRANSMISSION AND DISTRIBUTION
Electric utility companies often purchase electricity from independent power generators or the grid and resell it to end-consumers through a transmission and distribution (T&D) system6. A portion of the electricity purchased by a utility company is consumed (T&D loss) during its transmission and distribution to end-consumers (see Box 3 below).
Consistent with the scope 2 definition, emissions from the generation of purchased electricity that is consumed during transmission and distribution are reported in scope 2 by the company that owns or controls the T&D operation. End consumers of the purchased electricity do not report indirect emissions associated with T&D losses in scope 2 because they do not own or control the T&D operation where the electricity is consumed (T&D loss).
B O X 3 . Electricity balance |
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. GENERATED ELECTRICITY = .
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Purchased electricity consumed by the utility company during T&D |
+ |
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Purchased electricity consumed by end consumers |
This approach ensures that there is no double counting within scope 2 since only the T&D utility company will account for indirect emissions associated with T&D losses in scope 2. Another advantage of this approach is that it adds simplicity to the reporting of scope 2 emissions by allowing the use of commonly available emission factors that in most cases do not include T&D losses.
End consumers may, however, report their indirect emissions associated with T&D losses in scope 3 under the category “generation of electricity consumed in a T&D system.” Appendix A provides more guidance on accounting for emissions associated with T&D losses.
OTHER ELECTRICITY-RELATED INDIRECT EMISSIONS
Indirect emissions from activities upstream of a company’s electricity provider (e.g., exploration, drilling, flaring, transportation) are reported under scope 3. Emissions from the generation of electricity that has been purchased for resale to end-users are reported in scope 3 under the category “generation of electricity that is purchased and then resold to end users.”
Emissions from the generation of purchased electricity for resale to non-end-users (e.g., electricity traders) may be reported separately from scope 3 in “optional information.” The following two examples illustrate how GHG emissions are accounted for from the generation, sale, and purchase of electricity.
Example one (see figure GHG accounting from the sale and purchase of electricity): Company A is an independent power generator that owns a power generation plant. The power plant produces 100 MWh of electricity and releases 20 tonnes of emissions per year. Company B is an electricity trader and has a supply contract with company A to purchase all its electricity. Company B resells the purchased electricity (100 MWh) to company C, a utility company that owns / controls the T&D system.
Company C consumes 5 MWh of electricity in its T&D system and sells the remaining 95 MWh to company D. Company D is an end user who consumes the purchased electricity (95 MWh) in its own operations. Company A reports its direct emissions from power generation under scope 1. Company B reports emissions from the purchased electricity sold to a non-end-user as optional information separately from scope 3.
Company C reports the indirect emissions from the generation of the part of the purchased electricity that is sold to the end-user under scope 3 and the part of the purchased electricity that it consumes in its T&D system under scope 2. End-user D reports the indirect emissions associated with its own consumption of purchased electricity under scope 2 and can optionally report emissions associated with upstream T&D losses in scope 3.
The figure below shows the accounting of emissions associated with these transactions.
Example two: Company D installs a co-generation unit and sells surplus electricity to a neighboring company E for its consumption. Company D reports all direct emissions from the co-generation unit under scope 1. Indirect emissions from the generation of electricity for export to E are reported by D under optional information separately from scope 3.
Company E reports indirect emissions associated with the consumption of electricity purchased from the company D’s co-generation unit under scope 2. For more guidance, see Appendix A on accounting for indirect emissions from purchased electricity.
Seattle City Light: Accounting for the purchase of electricity sold to end users |
Seattle City Light (SCL), Seattle’s municipal utility company, sells electricity to its end-use customers that is either produced at its own hydropower facilities, purchased through long-term contracts, or purchased on the short-term market. SCL used the first edition of the GHG Protocol Corporate Standard to estimate its year 2000 and year 2002 GHG emissions, and emissions associated with generation of net purchased electricity sold to end-users was an important component of that inventory. SCL tracks and reports the amount of electricity sold to end-users on a monthly and annual basis. SCL calculates net purchases from the market (brokers and other utility companies) by subtracting sales to the market from purchases from the market, measured in MWh. This allows a complete accounting of all emissions impacts from its entire operation, including interactions with the market and end-users. On an annual basis, SCL produces more electricity than there is end-use demand, but the production does not match load in all months. So SCL accounts for both purchases from the market and sales into the market. SCL also includes the scope 3 upstream emissions from natural gas production and delivery, operation of SCL facilities, vehicle fuel use, and airline travel. SCL believes that sales to end-users are a critical part of the emissions profile for an electric utility company. Utility companies need to provide information on their emissions profile to educate end-users and adequately represent the impact of their business, the providing of electricity. End-use customers need to rely on their utility company to provide electricity, and except in some instances (green power programs), do not have a choice in where their electricity is purchased. SCL meets a customer need by providing emissions information to customers who are doing their own emissions inventory. |
Scope 3: Other indirect GHG emissions
Scope 3 is optional, but it provides an opportunity to be innovative in GHG management. Companies may want to focus on accounting for and reporting those activities that are relevant to their business and goals, and for which they have reliable information.
Since companies have discretion over which categories they choose to report, scope 3 may not lend itself well to comparisons across companies. This section provides an indicative list of scope 3 categories and includes case studies on some of the categories.
Some of these activities will be included under scope 1 if the pertinent emission sources are owned or controlled by the company (e.g., if the transportation of products is done in vehicles owned or controlled by the company). To determine if an activity falls within scope 1 or scope 3, the company should refer to the selected consolidation approach (equity or control) used in setting its organizational boundaries.
- E0xtraction and production of purchased materials and fuels7
- Transport-related activities
- Transportation of purchased materials or goods
- Transportation of purchased fuels
- Employee business travel
- Employees commuting to and from work
- Transportation of sold products
- Transportation of waste
- Electricity-related activities not included in scope 2 (see Appendix A Accounting for Indirect Emissions from Purchased Electricity)
- Extraction, production, and transportation of fuels consumed in the generation of electricity (either purchased or own generated by the reporting company)
- Purchase of electricity that is sold to an end user (reported by utility company)
- Generation of electricity that is consumed in a T&D system (reported by end-user)
- Leased assets, franchises, and outsourced activities—emissions from such contractual arrangements are only classified as scope 3 if the selected consolidation approach (equity or control) does not apply to them. Clarification on the classification of leased assets should be obtained from the company accountant (see section on leases below).
- Use of sold products and services
- Waste disposal
- Disposal of waste generated in operations
- Disposal of waste generated in the production of purchased materials and fuels
- Disposal of sold products at the end of their life
ACCOUNTING FOR SCOPE 3 EMISSIONS
Accounting for scope 3 emissions need not involve a full-blown GHG life cycle analysis of all products and operations. Usually it is valuable to focus on one or two major GHG-generating activities. Although it is difficult to provide generic guidance on which scope 3 emissions to include in an inventory, some general steps can be articulated:
1. Describe the value chain. Because the assessment of scope 3 emissions does not require a full life cycle assessment, it is important, for the sake of transparency, to provide a general description of the value chain and the associated GHG sources. For this step, the scope 3 categories listed can be used as a checklist.
Companies usually face choices on how many levels up- and downstream to include in scope 3. Consideration of the company’s inventory or business goals and relevance of the various scope 3 categories will guide these choices.
2. Determine which scope 3 categories are relevant. Only some types of upstream or downstream emissions categories might be relevant to the company. They may be relevant for several reasons:
- They are large (or believed to be large) relative to the company’s scope 1 and scope 2 emissions
- They contribute to the company’s GHG risk exposure
- They are deemed critical by key stakeholders (e.g., feedback from customers, suppliers, investors, or civil society)
- There are potential emissions reductions that could be undertaken or influenced by the company.
The following examples may help decide which scope 3 categories are relevant to the company.
- If fossil fuel or electricity is required to use the company’s products, product use phase emissions may be a relevant category to report. This may be especially important if the company can influence product design attributes (e.g., energy efficiency) or customer behavior in ways that reduce GHG emissions during the use of the products.
- Outsourced activities are often candidates for scope 3 emissions assessments. It may be particularly important to include these when a previously outsourced activity contributed significantly to a company’s scope 1 or scope 2 emissions.
- If GHG-intensive materials represent a significant fraction of the weight or composition of a product used or manufactured (e.g., cement, aluminium), companies may want to examine whether there are opportunities to reduce their consumption of the product or to substitute less GHG-intensive materials.
- Large manufacturing companies may have significant emissions related to transporting purchased materials to centralized production facilities.
- Commodity and consumer product companies may want to account for GHGs from transporting raw materials, products, and waste.
- Service sector companies may want to report on emissions from employee business travel; this emissions source is not as likely to be significant for other kinds of companies (e.g., manufacturing companies).
DHL Nordic Express: The business case for accounting for outsourced transportation services |
As a major transportation and logistics company in northern Europe, DHL Express Nordic serves large loads and special transport needs as well as world wide express package and document deliveries and offers courier, express, parcel, systemized and specialty business services. Through participation in the Business Leaders Initiative on Climate Change, the company found that 98 percent of its emissions in Sweden originate from the transport of goods via outsourced partner transportation firms. Each partner is required, as an element of the subcontract payment scheme, to enter data on vehicles used, distance travelled, fuel efficiency, and background data. This data is used to calculate total emissions via a tailored calculation tool for outsourced transportation which gives a detailed picture of its scope 3 emissions. Linking data to specific carriers allows the company to screen individual carriers for environmental performance and affect decisions based on each carrier’s emissions performance, which is seen through scope 3 as DHL’s own performance. By including scope 3 and promoting GHG reductions throughout the value chain, DHL Express Nordic increased the relevance of its emissions footprint, expanded opportunities for reducing its impacts and improved its ability to recognize cost saving opportunities. Without scope 3, DHL Express Nordic would have lacked much of the information needed to be able to understand and effectively manage its emissions.
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3. Identify partners along the value chain. Identify any partners that contribute potentially significant amounts of GHGs along the value chain (e.g., customers /users, product designers /manufacturers, energy providers, etc.). This is important when trying to identify sources, obtain relevant data, and calculate emissions.
4. Quantify scope 3 emissions. While data availability and reliability may influence which scope 3 activities are included in the inventory, it is accepted that data accuracy may be lower. It may be more important to understand the relative magnitude of and possible changes to scope 3 activities.
Emission estimates are acceptable as long as there is transparency with regard to the estimation approach, and the data used for the analysis are adequate to support the objectives of the inventory. Verification of scope 3 emissions will often be difficult and may only be considered if data is of reliable quality.
IKEA: Customer transportation to and from its retail stores |
IKEA, an international home furniture and furnishings retailer, decided to include scope 3 emissions from customer travel when it became clear, through participation in the Business Leaders Initiative on Climate Change (BLICC) program, that these emissions were large relative its scope 1 and scope 2 emissions. Furthermore, these emissions are particularly relevant to IKEA’s store business model. Customer travel to its stores, often from long distances, is directly affected by IKEA’s choice of store location and the warehouse shopping concept. Customer transportation emission calculations were based on customer surveys at selected stores. Customers were asked for the distance they traveled to the store (based on home postal code), the number of customers in their car, the number of other stores they intended to visit at that shopping center that day, and whether they had access to public transportation to the store. Extrapolating this data to all IKEA stores and multiplying distance by average vehicle efficiencies for each country, the company calculated that 66 percent of its emissions inventory was from scope 3 customer travel. Based on this information, IKEA will have significant influence over future scope 3 emissions by consideringGHG emissions when developing public transportation options and home delivery services for its existing and new stores. |
Leased assets, outsourcing, and franchises
The selected consolidation approach (equity share or one of the control approaches) is also applied to account for and categorize direct and indirect GHG emissions from contractual arrangements such as leased assets, outsourcing, and franchises. If the selected equity or control approach does not apply, then the company may account for emissions from the leased assets, outsourcing, and franchises under scope 3. Specific guidance on leased assets is provided below:
- USING EQUITY SHARE OR FINANCIAL CONTROL: The lessee only accounts for emissions from leased assets that are treated as wholly owned assets in financial accounting and are recorded as such on the balance sheet (i.e., finance or capital leases).
- USING OPERATIONAL CONTROL: The lessee only accounts for emissions from leased assets that it operates (i.e., if the operational control criterion applies).
Guidance on which leased assets are operating and which are finance leases should be obtained from the company accountant. In general, in a finance lease, an organization assumes all rewards and risks from the leased asset, and the asset is treated as wholly owned and is recorded as such on the balance sheet. All leased assets that do not meet those criteria are operating leases.
The figure below illustrates the application of consolidation criteria to account for emissions from leased assets.
Double counting
Concern is often expressed that accounting for indirect emissions will lead to double counting when two different companies include the same emissions in their respective inventories.
Whether or not double counting occurs depends on how consistently companies with shared ownership or trading program administrators choose the same approach (equity or control) to set the organizational boundaries. Whether or not double counting matters, depends on how the reported information is used.
Double counting needs to be avoided when compiling national (country) inventories under the Kyoto Protocol, but these are usually compiled via a top-down exercise using national economic data, rather than aggregation of bottom-up company data.
Compliance regimes are more likely to focus on the “point of release” of emissions (i.e., direct emissions) and/or indirect emissions from use of electricity. For GHG risk management and voluntary reporting, double counting is less important.
World Resources Institute: Innovations in estimating employee commuting emissions |
The World Resources Institute has a long-standing commitment to reduce its annual GHG emissions to net zero through a combination of internal reduction efforts and external offset purchases. WRI’s emissions inventory includes scope 2 indirect emissions associated with the consumption of purchased electricity and scope 3 indirect emissions associated with business air travel, employee commuting, and paper use. WRI has no scope 1 direct emissions. Collecting employee commuting activity data from WRI’s 140 staff can be challenging. The method used is to survey employees once each year about their average commuting habits. In the first two years of the initiative, WRI used an Excel spreadsheet accessible to all employees on a shared internal network, but only achieved a 48 percent participation rate. A simplified, web-based survey that downloaded into a spreadsheet improved participation to 65 percent in the third year. Using feedback on the survey design, WRI further simplified and refined survey questions, improved user friendliness, and reduced the time needed to complete the survey to less than a minute. Employee participation rate rose to 88 percent. Designing a survey that was easily navigable and had clearly articulated questions significantly improved the completeness and accuracy of the employee commuting activity data. An added benefit was that employees felt a certain amount of pride at having contributed to the inventory development process. The experience also provided a positive internal communications opportunity. WRI has developed a guide consistent with GHG Protocol Corporate Standard to help office-based organizations understand how to track and manage their emissions. Working 9 to 5 on Climate Change: An Office Guide is accompanied by a suite of calculation tools, including one for using a survey method to estimate employee commuting emissions. The Guide and tools can be downloaded from the GHG Protocol Initiative website (www.ghgprotocol.org). Transportation-related emissions are the fastest growing GHG emissions category in the United States. This includes commercial, business, and personal travel as well as commuting. By accounting for commuting emissions, companies may find that several practical opportunities exist for reducing them. For example, when WRI moved to new office space, it selected a building located close to public transportation, reducing the need for employees to drive to work. In its lease, WRI also negotiated access to a locked bike room for those employees who cycle to work. Finally, telework programs significantly reduce commuting emissions by avoiding or decreasing the need to travel. |
For participating in GHG markets or obtaining GHG credits, it would be unacceptable for two organizations to claim ownership of the same emissions commodity and it is therefore necessary to make sufficient provisions to ensure that this does not occur between participating companies (see Guidance 11 Setting GHG Targets).
SCOPES AND DOUBLE COUNTING
The GHG Protocol Corporate Standard is designed to prevent double counting of emissions between different companies within scope 1 and 2.
For example, the scope 1 emissions of company A (generator of electricity) can be counted as the scope 2 emissions of company B (end-user of electricity) but company A’s scope 1 emissions cannot be counted as scope 1 emissions by company C (a partner organization of company A) as long as company A and company C consistently apply the same control or equity share approach when consolidating emissions.
Similarly, the definition of scope 2 does not allow double counting of emissions within scope 2, i.e., two different companies cannot both count scope 2 emissions from the purchase of the same electricity.
Avoiding this type of double counting within scope 2 emissions makes it a useful accounting category for GHG trading programs that regulate end users of electricity.
When used in external initiatives such as GHG trading, the robustness of the scope 1 and 2 definitions combined with the consistent application of either the control or equity share approach for defining organizational boundaries allows only one company to exercise ownership of scope 1 or scope 2 emissions.
ABB: Calculating product use phase emissions associated with electrical appliances |
ABB, an energy and automation technology company based in Switzerland, produces a variety of appliances and equipment, such as circuit breakers and electrical drives, for industrial applications. ABB has a stated goal to issue Environmental Product Declarations (EPDs) for all its core products based on life cycle assessment. As a part of its committment, ABB reports both manufacturing and product use phase GHG emissions for a variety of its products using a standardized calculation method and set of assumptions. For example, product use phase calculations for ABB’s 4 kW DriveIT Low Voltage AC drive are based on a 15-year expected lifetime and an average of 5,000 annual operating hours. This activity data is multiplied by the average electricity emission factor for OECD countries to produce total lifetime product use emissions. Compared with manufacturing emissions, product use phase emissions account for about 99 percent of total life cycle emissions for this type of drive. The magnitude of these emissions and ABB’s control of the design and performance of this equipment clearly give the company significant leverage on its customers’ emissions by improving product efficiency or helping customers design better overall systems in which ABB’s products are involved. By clearly defining and quantifying significant value chain emissions, ABB has gained insight into and influence over its emissions footprint. |
Standard 5 Tracking Emissions Over Time
Companies often undergo significant structural changes such as acquisitions, divestments, and mergers. These changes will alter a company’s historical emission profile, making meaningful comparisons over time difficult.
In order to maintain consistency over time, or in other words, to keep comparing “like with like”, historic emission data will have to be recalculated.
Companies may need to track emissions over time in response to a variety of business goals, including:
- Public reporting
- Establishing GHG targets
- Managing risks and opportunities
- Addressing the needs of investors and other stakeholders
A meaningful and consistent comparison of emissions over time requires that companies set a performance datum with which to compare current emissions. This performance datum is referred to as the base year8 emissions.
For consistent tracking of emissions over time, the base year emissions may need to be recalculated as companies undergo significant structural changes such as acquisitions, divestments, and mergers.
The first step in tracking emissions, however, is the selection of a base year.
Choosing a base year
Companies shall choose and report a base year for which verifiable emissions data are available and specify their reasons for choosing that particular year.
Most companies select a single year as their base year. However, it is also possible to choose an average of annual emissions over several consecutive years. For example, the U.K. ETS specifies an average of 1998–2000 emissions as the reference point for tracking reductions. A multi-year average may help smooth out unusual fluctuations in GHG emissions that would make a single year’s data unrepresentative of the company’s typical emissions profile.
The inventory base year can also be used as a basis for setting and tracking progress towards a GHG target in which case it is referred to as a target base year (see Guidance 11 Setting GHG Targets).
Recalculating base year emissions
Companies shall develop a base year emissions recalculation policy, and clearly articulate the basis and context for any recalculations. If applicable, the policy shall state any “significance threshold” applied for deciding on historic emissions recalculation. “Significance threshold” is a qualitative and/or quantitative criterion used to define any significant change to the data, inventory boundary, methods, or any other relevant factors.
It is the responsibility of the company to determine the “significance threshold” that triggers base year emissions recalculation and to disclose it. It is the responsibility of the verifier to confirm the company’s adherence to its threshold policy. The following cases shall trigger recalculation of base year emissions:
- Structural changes in the reporting organization that have a significant impact on the company’s base year emissions. A structural change involves the transfer of ownership or control of emissions-generating activities or operations from one company to another. While a single structural change might not have a significant impact on the base year emissions, the cumulative effect of a number of minor structural changes can result in a significant impact. Structural changes include:
- Mergers, acquisitions, and divestments
- Outsourcing and insourcing of emitting activities
- Changes in calculation methodology or improvements in the accuracy of emission factors or activity data that result in a significant impact on the base year emissions data
- Discovery of significant errors, or a number of cumulative errors, that are collectively significant.
In summary, base year emissions shall be retroactively recalculated to reflect changes in the company that would otherwise compromise the consistency and relevance of the reported GHG emissions information. Once a company has determined its policy on how it will recalculate base year emissions, it shall apply this policy in a consistent manner. For example, it shall recalculate for both GHG emissions increases and decreases.
Guidance 5 Tracking Emissions Over Time
Election and recalculation of a base year should relate to the business goals and the particular context of the company:
- For the purpose of reporting progress towards voluntary public GHG targets, companies may follow the standards and guidance in this chapter
- A company subject to an external GHG program may face external rules governing the choice and recalculation of base year emissions
- For internal management goals, the company may follow the rules and guidelines recommended in this document, or it may develop its own approach, which should be followed consistently.
Choosing a base year
Companies should choose as a base year the earliest relevant point in time for which they have reliable data. Some organizations have adopted 1990 as a base year in order to be consistent with the Kyoto Protocol. However, obtaining reliable and verifiable data for historical base years such as 1990 can be very challenging.
If a company continues to grow through acquisitions, it may adopt a policy that shifts or “rolls” the base year forward by a number of years at regular intervals.
Guidance 11 Setting GHG Targets contains a description of such a “rolling base year,” including a comparison with the fixed base year approach described in this chapter. A fixed base year has the advantage of allowing emissions data to be compared on a like-with-like basis over a longer time period than a rolling base year approach. Most emissions trading and registry programs require a fixed base year policy to be implemented.
Significance thresholds for recalculations
Whether base year emissions are recalculated depends on the significance of the changes. The determination of a significant change may require taking into account the cumulative effect on base year emissions of a number of small acquisitions or divestments. The GHG Protocol Corporate Standard makes no specific recommendations as to what constitutes “significant.”
However, some GHG programs do specify numerical significance thresholds, e.g., the California Climate Action Registry, where the change threshold is 10 percent of the base year emissions, determined on a cumulative basis from the time the base year is established.
Base year emissions recalculation for structural changes
Structural changes trigger recalculation because they merely transfer emissions from one company to another without any change of emissions released to the atmosphere, for example, an acquisition or divestment only transfers existing GHG emissions from one company’s inventory to another.
The figures Base year emissions recalculation for an acquisition and Base year emissions recalculation for a divestment illustrate the effect of structural changes and the application of this standard on recalculation of base year emissions.
Company Gamma consists of two business units (A and B). In its base year (year one), each business unit emits 25 tonnes CO2. In year two, the company undergoes “organic growth,” leading to an increase in emissions to 30 tonnes CO2 per business unit, i.e., 60 tonnes CO2 in total. The base year emissions are not recalculated in this case. At the beginning of year three, the company acquires production facility C from another company. The annual emissions of facility C in year one were 15 tonnes CO2, and 20 tonnes CO2 in years two and three. The total emission of company Gamma in year three, including facility C, are therefore 80 tonnes CO2. To maintain consistency over time, the company recalculates its base year emissions to take into account the acquisition of facility C. The base year emissions increase by 15 tonnes CO2—the quantity of emissions produced by facility C in Gamma’s base year. The recalculated base year emissions are 65 tonnes CO2. Gamma also (optionally) reports 80 tonnes CO2 as the recalculated emissions for year two. |
Company Beta consists of three business units (A, B, and C). Each business unit emits 25 tonnes CO2 and the total emissions for the company are 75 tonnes CO2 in the base year (year one).
In year two, the output of the company grows, leading to an increase in emissions to 30 tonnes CO2 per business unit, i.e., 90 tonnes CO2 in total. At the beginning of year three, Beta divests business unit C and its annual emissions are now 60 tonnes, representing an apparent reduction of 15 tonnes relative to the base year emissions. However, to maintain consistency over time, the company recalculates its base year emissions to take into account the divestment of business unit C. The base year emissions are lowered by 25 tonnes CO2—the quantity of emissions produced by the business unit C in the base year. The recalculated base year emissions are 50 tonnes CO2, and the emissions of company Beta are seen to have risen by 10 tonnes CO2 over the three years. Beta (optionally) reports 60 tonnes CO2 as the recalculated emissions for year two. |
Timing of recalculations for structural changes
When significant structural changes occur during the middle of the year, the base year emissions should be recalculated for the entire year, rather than only for the remainder of the reporting period after the structural change occurred. This avoids having to recalculate base year emissions again in the succeeding year. Similarly, current year emissions should be recalculated for the entire year to maintain consistency with the base year recalculation.
If it is not possible to make a recalculation in the year of the structural change (e.g., due to lack of data for an acquired company), the recalculation may be carried out in the following year9.
Recalculations for changes in calculation methodology or improvements in data accuracy
A company might report the same sources of GHG emissions as in previous years, but measure or calculate them differently. For example, a company might have used a national electric power generation emissions factor to estimate scope 2 emissions in year one of reporting. In later years, it may obtain more accurate utility-specific emission factors (for the current as well as past years) that better reflect the GHG emissions associated with the electricity that it has purchased.
If the differences in emissions resulting from such a change are significant, historic data is recalculated applying the new data and/or methodology.
Sometimes the more accurate data input may not reasonably be applied to all past years or new data points may not be available for past years. The company may then have to backcast these data points, or the change in data source may simply be acknowledged without recalculation.
This acknowledgement should be made in the report each year in order to enhance transparency; otherwise, new users of the report in the two or three years after the change may make incorrect assumptions about the performance of the company.
Any changes in emission factor or activity data that reflect real changes in emissions (i.e., changes in fuel type or technology) do not trigger a recalculation.
Optional reporting for recalculations
Optional information that companies may report on recalculations includes:
- The recalculated GHG emissions data for all years between the base year and the reporting year
- All actual emissions as reported in respective years in the past, i.e., the figures that have not been recalculated. Reporting the original figures in addition to the recalculated figures contributes to transparency since it illustrates the evolution of the company’s structure over time.
No base year emissions recalculations for facilities that did not exist in the base year
Base year emissions are not recalculated if the company makes an acquisition of (or insources) operations that did not exist in its base year. There may only be a recalculation of historic data back to the year in which the acquired company came into existence. The same applies to cases where the company makes a divestment of (or outsources) operations that did not exist in the base year.
The figure and case description below illustrates a situation where no recalculation of base year emissions is required, since the acquired facility came into existence after the base year was set.
Case description – Company Teta consists of two business units (A and B). In its base year (year one), the company emits 50 tonnes CO2. In year two, the company undergoes organic growth, leading to an increase in emissions to 30 tonnes CO2 per business unit, i.e., 60 tonnes CO2 in total. The base year emissions are not recalculated in this case. At the beginning of year three, Teta acquires a production facility C from another company. Facility C came into existence in year two, its emissions being 15 tonnes CO2 in year two and 20 tonnes CO2 in year three.
The total emissions of company Teta in year three, including facility C, are therefore 80 tonnes CO2. In this acquisition case, the base year emissions of company Teta do not change because the acquired facility C did not exist in year one when the base year of Teta was set. The base year emissions of Teta therefore remain at 50 tonnes CO2. Teta (optionally) reports 75 tonnes as the recalculated figure for year two emissions.
No recalculation for “ outsourcing/insourcing” if reported under scope 2 and/or scope 3
Structural changes due to “outsourcing” or “insourcing” do not trigger base year emissions recalculation if the company is reporting its indirect emissions from relevant outsourced or insourced activities. For example, outsourcing production of electricity, heat, or steam does not trigger base year emissions recalculation, since the GHG Protocol Corporate Standard requires scope 2 reporting. However, outsourcing/insourcing that shifts significant emissions between scope 1 and scope 3 when scope 3 is not reported does trigger a base year emissions recalculation (e.g., when a company outsources the transportation of products).
In case a company decides to track emissions over time separately for different scopes, and has separate base years for each scope, base year emissions recalculation for outsourcing or insourcing is made.
ENDESA: Recalculation of base year emissions because of structural changes |
The GHG Protocol Corporate Standard requires setting a base year for comparing emissions over time. To be able to compare over time, the base year emissions must be recalculated if any structural changes occur in the company. In a deal completed January 2002, the ENDESA Group, a power generation company based in Spain, sold its 87.5 percent holding in Viesgo, a part of its Spanish power generation business, to ENEL, an Italian power company. To account for this structural change, historical emissions from the six power plants included in the sale were no longer accounted for in the Endesa GHG inventory and therefore removed from its base year emissions. This recalculation provides ENDESA with a complete and comparable picture of its historical emissions. |
No recalculation for organic growth or decline Base year emissions and any historic data are not recalculated for organic growth or decline. Organic growth/decline refers to increases or decreases in production output, changes in product mix, and closures and openings of operating units that are owned or controlled by the company. The rationale for this is that organic growth or decline results in a change of emissions to the atmosphere and therefore needs to be counted as an increase or decrease in the company’s emissions profile over time.
Guidance 6 Identifying and Calculating GHG Emissions
Once the inventory boundary has been established, companies generally calculate GHG emissions using the following steps:
- Identify GHG emissions sources GHG Protocol Corporate Standard GHG Protocol Corporate Standard
- Select a GHG emissions calculation approach GHG Protocol Corporate Standard GHG Protocol Corporate Standard
- Collect activity data and choose emission factors GHG Protocol Corporate Standard GHG Protocol Corporate Standard
- Apply calculation tools GHG Protocol Corporate Standard GHG Protocol Corporate Standard
- Roll-up GHG emissions data to corporate level. GHG Protocol Corporate Standard GHG Protocol Corporate Standard
This chapter describes these steps and the calculation tools developed by the GHG Protocol. The calculation tools are available on the GHG Protocol Initiative website at www.ghgprotocol.org.
To create an accurate account of their emissions, companies have found it useful to divide overall emissions into specific categories. This allows a company to use specifically developed methodologies to accurately calculate the emissions from each sector and source category.
Identify GHG emissions sources
The first of the five steps in identifying and calculating a company’s emissions as outlined in the figure 9 ‘Steps in identifying and calculating GHG emissions’ is to categorize the GHG sources within that company’s boundaries. GHG emissions typically occur from the following source categories:
- Stationary combustion: combustion of fuels in stationary equipment such as boilers, furnaces, burners, turbines, heaters, incinerators, engines, flares, etc.
- Mobile combustion: combustion of fuels in transportation devices such as automobiles, trucks, buses, trains, airplanes, boats, ships, barges, vessels, etc.
- Process emissions: emissions from physical or chemical processes such as CO2 from the calcination step in cement manufacturing, CO2 from catalytic cracking in petrochemical processing, PFC emissions from aluminium smelting, etc.
- Fugitive emissions: intentional and unintentional releases such as equipment leaks from joints, seals, packing, gaskets, as well as fugitive emissions from coal piles, wastewater treatment, pits, cooling towers, gas processing facilities, etc.
Every business has processes, products, or services that generate direct and/or indirect emissions from one or more of the above broad source categories. The GHG Protocol calculation tools are organized based on these categories. Appendix D provides an overview of direct and indirect GHG emission sources organized by scopes and industry sectors that may be used as an initial guide to identify major GHG emission sources.
IDENTIFY SCOPE 1 EMISSIONS
As a first step, a company should undertake an exercise to identify its direct emission sources in each of the four source categories listed above. Process emissions are usually only relevant to certain industry sectors like oil and gas, aluminium, cement, etc.
Manufacturing companies that generate process emissions and own or control a power production facility will likely have direct emissions from all the main source categories. Office-based organizations may not have any direct GHG emissions except in cases where they own or operate a vehicle, combustion device, or refrigeration and air-conditioning equipment. Often companies are surprised to realize that significant emissions come from sources that are not initially obvious (see United Technologies case study below). GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
IDENTIFY SCOPE 2 EMISSIONS
The next step is to identify indirect emission sources from the consumption of purchased electricity, heat, or steam. Almost all businesses generate indirect emissions due to the purchase of electricity for use in their processes or services.
IDENTIFY SCOPE 3 EMISSIONS
This optional step involves identification of other indirect emissions from a company’s upstream and downstream activities as well as emissions associated with outsourced/contract manufacturing, leases, or franchises not included in scope 1 or scope 2.
The inclusion of scope 3 emissions allows businesses to expand their inventory boundary along their value chain and to identify all relevant GHG emissions. This provides a broad overview of various business linkages and possible opportunities for significant GHG emission reductions that may exist upstream or downstream of a company’s immediate operations (see Standard 4 Setting Operational Boundaries for an overview of activities that can generate GHG emissions along a company’s value chain).
Select a calculation approach
Direct measurement of GHG emissions by monitoring concentration and flow rate is not common. More often, emissions may be calculated based on a mass balance or stoichiometric basis specific to a facility or process.
However, the most common approach for calculating GHG emissions is through the application of documented emission factors. These factors are calculated ratios relating GHG emissions to a proxy measure of activity at an emissions source. The IPCC guidelines (IPCC, 1996) refer to a hierarchy of calculation approaches and techniques ranging from the application of generic emission factors to direct monitoring.
In many cases, particularly when direct monitoring is either unavailable or prohibitively expensive, accurate emission data can be calculated from fuel use data. Even small users usually know both the amount of fuel consumed and have access to data on the carbon content of the fuel through default carbon content coefficients or through more accurate periodic fuel sampling.
Companies should use the most accurate calculation approach available to them and that is appropriate for their reporting context.
Collect activity data and choose emission factors
For most small to medium-sized companies and for many larger companies, scope 1 GHG emissions will be calculated based on the purchased quantities of commercial fuels (such as natural gas and heating oil) using published emission factors. Scope 2 GHG emissions will primarily be calculated from metered electricity consumption and supplier-specific, local grid, or other published emission factors. Scope 3 GHG emissions will primarily be calculated from activity data such as fuel use or passenger miles and published or third-party emission factors. In most cases, if source- or facility-specific emission factors are available, they are preferable to more generic or general emission factors.
Industrial companies may be faced with a wider range of approaches and methodologies. They should seek guidance from the sector-specific guidelines on the GHG Protocol website (if available) or from their industry associations (e.g., International aluminium Institute, International Iron and Steel Institute, American Petroleum Institute, WBCSD Sustainable Cement Initiative, International Petroleum Industry Environmental Conservation Association).
Apply calculation tools
This section provides an overview of the GHG calculation tools and guidance available on the GHG Protocol Initiative website (www.ghgprotocol.org). Use of these tools is encouraged as they have been peer reviewed by experts and industry leaders, are regularly updated, and are believed to be the best available. The tools, however, are optional. Companies may substitute their own GHG calculation methods, provided they are more accurate than or are at least consistent with the GHG Protocol Corporate Standards approaches. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
There are two main categories of calculation tools: GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
- Cross-sector tools that can be applied to different sectors. These include stationary combustion, mobile combustion, HFC use in refrigeration and air conditioning, and measurement and estimation uncertainty.
- Sector-specific tools that are designed to calculate emissions in specific sectors such as aluminium, iron and steel, cement, oil and gas, pulp and paper, office-based organizations.
United Technologies Corporation: More than meets the eye |
In 1996, United Technologies Corporation (UTC), a global aerospace and building systems technology corporation, appointed a team to set boundaries for the company’s new Natural Resource Conservation, Energy and Water Use Reporting Program. The team focused on what sources of energy should be included in the program’s annual report of energy consumption. The team decided jet fuel needed to be reported in the annual report; jet fuel was used by a number of UTC divisions for engine and flight hardware testing and for test firing. Although the amount of jet fuel used in any given year was subject to wide variation due to changing test schedules, the total amount consumed in an average year was believed to be large and potentially small enough to be specifically excluded. However, jet fuel consumption reports proved that initial belief incorrect. Jet fuel has accounted for between 9 and 13 percent of the corporation’s total annual use of energy since the program commenced. Had UTC not included the use of jet fuel in annual data collection efforts, a significant emissions source would have been overlooked. |
Most companies will need to use more than one calculation tool to cover all their GHG emission sources. For example, to calculate GHG emissions from an aluminium production facility, the company would use the calculation tools for aluminium production, stationary combustion (for any consumption of purchased electricity, generation of energy on-site, etc), mobile combustion (for transportation of materials and products by train, vehicles employed on-site, employee business travel, etc), and HFC use (for refrigeration, etc). See the table below for the full list of tools. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
STRUCTURE OF GHG Protocol Corporate Standard CALCULATION TOOLS
Each of the cross-sector and sector-specific calculation tools on the website share a common format and include step-by-step guidance on measuring and calculating emissions data. Each tool consists of a guidance section and automated worksheets with explanations on how to use them. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
The guidance for each calculation tool includes the following sections: GHG Protocol Corporate Standard
- Overview: provides an overview of the purpose and content of the tool, the calculation method used in the tool, and a process description
- Choosing activity data and emission factors: provides sector-specific good practice guidance and references for default emission factors
- Calculation methods: describes different calculation methods depending on the availability of site-specific activity data and emission factors
- Quality control: provides good practice guidance
- Internal reporting and documentation: provides guidance on internal documentation to support emissions calculations.
ChevronTexaco: The SANGEATM accounting and reporting system |
ChevronTexaco, a global energy company, has developed and implemented energy utilization and GHG estimation and reporting software consistent with the GHG Protocol Corporate Standard. This software is available free of charge and makes it easier, more accurate, and less costly to institute a corporate-wide GHG accounting and reporting system in the oil and gas sector. Called the SANGEA™ Energy and Greenhouse Gas Emissions Estimating System, it is currently in use at all ChevronTexaco facilities worldwide, comprising more than 70 reporting entities. The system is an auditable, Excel-and-Visual-Basic-based tool for estimating GHG emissions and energy utilization. It streamlines corporate-level data consolidation by allowing the inventory coordinator at each facility to configure a spreadsheet, enter monthly data, and send quarterly reports to a centralized database. In practice, the SANGEA™ system employs a variety of strategies to ensure consistent calculation methods and ease company-wide standardization:
Updates will mirror the timing and content of updates to the American Petroleum Institute Compendium of GHG emission estimating methodologies.
ChevronTexaco’s one-off investment in developing the SANGEA™ system has already shown results: A rough cost estimate for ChevronTexaco’s Richmond, California, refinery indicates savings of more than 70 percent over a five-year period compared with the conventional approaches based on locally developed reporting systems. SANGEA™ is expected to reduce the long term expenses of maintaining a legacy system and hiring independent consultants. Employing a combination of the GHG Protocol Corporate Standards and SANGEA™ calculation software to replace a diverse and confusing set of accounting and reporting templates yields significant efficiency and accuracy gains, and allows the company to more accurately manage GHG emissions and institute specific emissions improvements. |
In the automated worksheet section, it is only necessary to insert activity data into the worksheets and to select an appropriate emission factor or factors. Default emission factors are provided for the sectors covered, but it is also possible to insert customized emission factors that are more representative of the reporting company’s operations.
The emissions of each GHG (CO2, CH4, N2O, etc.) are calculated separately and then converted to CO2 equivalents on the basis of their global warming potential. Some tools, such as the iron and steel sector tool and the HFC cross-sector tool, take a tiered approach, offering a choice between a simple and a more advanced calculation methodology. The more advanced methods are expected to produce more accurate emissions estimates but usually require collection of more detailed data and a more thorough understanding of a company’s technologies. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
Roll-up GHG emissions data to corporate level
To report a corporation’s total GHG emissions, companies will usually need to gather and summarize data from multiple facilities, possibly in different countries and business divisions. It is important to plan this process carefully to minimize the reporting burden, reduce the risk of errors that might occur while compiling data, and ensure that all facilities are collecting information on an approved, consistent basis.
Ideally, corporations will integrate GHG reporting with their existing reporting tools and processes, and take advantage of any relevant data already collected and reported by facilities to division or corporate offices, regulators or other stakeholders.
The tools and processes chosen to report data will depend upon the information and communication infrastructure already in place (i.e., how easy is it to include new data categories in corporate databases). It will also depend upon the amount of detail that corporate headquarters wishes to be reported from facilities. Data collection and management tools could include:
- Secure databases available over the company intranet or internet, for direct data entry by facilities
- Spreadsheet templates filled out and e-mailed to a corporate or division office, where data is processed further
- Paper reporting forms faxed to a corporate or division office where data is re-entered in a corporate database.
However, this method may increase the likelihood of errors if there are not sufficient checks in place to ensure the accurate transfer of the data. For internal reporting up to the corporate level, it is recommended that standardized reporting formats be used to ensure that data received from different business units and facilities is comparable, and that internal reporting rules are observed (see BP case study). Standardized formats can significantly reduce the risk of errors.
BP: A standardized system for internal reporting of GHGs |
BP, a global energy company, has been collecting GHG data from the different parts of its operations since 1997 and has consolidated its internal reporting processes into one central database system. The responsibility for reporting environmental emissions lies with about 320 individual BP facilities and business departments, which are termed “reporting units.” All reporting units have to complete a standard Excel pro-forma spreadsheet every quarter, stating actual emissions for the preceding three months and updates to forecasts for the current year and the next two years. In addition, reporting units are asked to account for all significant variances, including sustainable reductions. The reporting units all use the same BP GHG Reporting Guidelines “Protocol” (BP, 2000) for quantifying their emissions of carbon dioxide and methane. All pro-forma spreadsheets are e-mailed automatically by the central database to the reporting units, and the completed e-mail returns are uploaded into the database by a corporate team, who check the quality of the incoming data. The data are then compiled, by the end of the month following each quarter end, to provide the total emission inventory and forecasts for analysis against BP’s GHG target. Finally, the inventory is reviewed by a team of independent external auditors to provide assurance on the quality and accuracy of the data. |
GHG Protocol Corporate Standard – Approaches for rolling up GHG emissions data to corporate level
There are two basic approaches for gathering data on GHG emissions from a corporation’s facilities (see figure Approaches to gathering data below):
- Centralized: individual facilities report activity/fuel use data (such as quantity of fuel used) to the corporate level, where GHG emissions are calculated.
- Decentralized: individual facilities collect activity/fuel use data, directly calculate their GHG emissions using approved methods, and report this data to the corporate level.
The difference between these two approaches is in where the emissions calculations occur (i.e., where activity data is multiplied by the appropriate emission factors) and in what type of quality management procedures must be put in place at each level of the corporation. Facility-level staff is generally responsible for initial data collection under both approaches.
Under both approaches, staff at corporate and lower levels of consolidation should take care to identify and exclude any scope 2 or 3 emissions that are also accounted for as scope 1 emissions by other facilities, business units, or companies included in the emissions inventory consolidation. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
CENTRALIZED APPROACH: INDIVIDUAL FACILITIES REPORT ACTIVITY/FUEL USE DATA
This approach may be particularly suitable for office-based organizations. Requesting that facilities report their activity/fuel use data may be the preferred option if:
- The staff at the corporate or division level can calculate emissions data in a straightforward manner on the basis of activity/fuel use data; and
- Emissions calculations are standard across a number of facilities. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
DECENTRALIZED APPROACH:INDIVIDUAL FACILITIES CALCULATE GHG EMISSIONS DATA
Asking facilities to calculate GHG emissions themselves will help to increase their awareness and understanding of the issue. However, it may also lead to resistance, increased training needs, an increase in calculation errors, and a greater need for auditing of calculations. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
Requesting that facilities calculate GHG emissions themselves may be the preferred option if: GHG Protocol Corporate Standard
- GHG emission calculations require detailed knowledge of the kind of equipment being used at facilities; GHG Protocol Corporate Standard
- GHG emission calculation methods vary across a number of facilities; GHG Protocol Corporate Standard
- Process emissions (in contrast to emissions from burning fossil fuels) make up an important share of total GHG emissions; GHG Protocol Corporate Standard
- • Resources are available to train facility staff to conduct these calculations and to audit them; GHG Protocol Corporate Standard
- A user-friendly tool is available to simplify the calculation and reporting task for facility-level staff; or GHG Protocol Corporate Standard
- Local regulations require reporting of GHG emissions at a facility level. GHG Protocol Corporate Standard
The choice of collection approach depends on the needs and characteristics of the reporting company. For example, United Technologies Corporation uses the centralized approach, leaving the choice of emission factors and calculations to corporate staff, while BP uses the decentralized approach and follows up with audits to ensure calculations are correct, documented, and follow approved methods. To maximize accuracy and minimize reporting burdens, some companies use a combination of the two approaches. GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard GHG Protocol Corporate Standard
Complex facilities with process emissions calculate their emissions at the facility level, while facilities with uniform emissions from standard sources only report fuel use, electricity consumption, and travel activity. The corporate database or reporting tool then calculates total GHG emissions for each of these standard activities.
The two approaches are not mutually exclusive and should produce the same result. Thus companies desiring a consistency check on facility-level calculations can follow both approaches and compare the results. Even when facilities calculate their own GHG emissions, corporate staff may still wish to gather activity/fuel use data to double-check calculations and explore opportunities for emissions reductions. These data should be available and transparent to staff at all corporate levels. Corporate staff should also verify that facility-reported data are based on well defined, consistent, and approved inventory boundaries, reporting periods, calculation methodologies, etc.
Common guidance on reporting to corporate level Reports from facility level to corporate or division offices should include all relevant information as specified in Standard 9 Reporting GHG Emissions. Some reporting categories are common to both the centralized and decentralized approaches and should be reported by facilities to their corporate offices. These include:
- A brief description of the emission sources GHG Protocol Corporate Standard
- A list and justification of specific exclusion or inclusion of sources GHG Protocol Corporate Standard
- Comparative information from previous years GHG Protocol Corporate Standard
- The reporting period covered GHG Protocol Corporate Standard
- Any trends evident in the data GHG Protocol Corporate Standard
- Progress towards any business targets GHG Protocol Corporate Standard
- A discussion of uncertainties in activity/fuel use or emissions data reported, their likely cause, and recommendations for how data can be improved
- A description of events and changes that have an impact on reported data (acquisitions, divestitures, closures, technology upgrades, changes of reporting boundaries or calculation methodologies applied, etc.).
REPORTING FOR THE CENTRALIZED APPROACH
In addition to the activity/fuel use data and aforementioned common categories of reporting data, facilities following the centralized approach by reporting activity/fuel use data to the corporate level should also report the following:
- Activity data for freight and passenger transport activities (e.g., freight transport in tonne-kilometers)
- Activity data for process emissions (e.g., tonnes of fertilizer produced, tonnes of waste in landfills)
- Clear records of any calculations undertaken to derive activity/fuel use data
- Local emission factors necessary to translate fuel use and/or electricity consumption into CO2 emissions.
REPORTING FOR THE DECENTRALIZED APPROACH
In addition to the GHG emissions data and aforementioned common categories of reporting data, individual facilities following the decentralized approach by reporting calculated GHG emissions to the corporate level should also report the following:
- A description of GHG calculation methodologies and any changes made to those methodologies relative to previous reporting periods
- Ratio indicators (see Standard 9 Reporting GHG Emissions)
- Details on any data references used for the calculations, in particular information on emission factors used.
Clear records of calculations undertaken to derive emissions data should be kept for any future internal or external verification.
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