Scope 2 carbon accounting refers to the greenhouse gas emissions associated with an organization’s purchased electricity, heat, or steam. Unlike direct emissions from on-site fuel combustion (Scope 1), Scope 2 covers indirect emissions that occur at the facilities where energy is generated, but are attributable to the organization’s energy use.
For most electricity-intensive organizations, electricity consumption represents a large share of operational emissions. As a result, Scope 2 is a central component of carbon reporting and climate strategies.
Within the greenhouse gas accounting framework, Scope 2 sits between:
Scope 2 emissions are tightly connected to operational choices. Electricity emissions depend not only on how much energy is consumed, but also on how electricity is produced on the grid at the time and place of consumption. This link between energy use and power system conditions explains why Scope 2 has become increasingly important — and increasingly complex — over time.
Under widely used greenhouse gas accounting frameworks — most notably the GHG Protocol Corporate Standard and its Scope 2 Guidance, the de facto global reference for corporate carbon reporting — Scope 2 emissions are calculated by combining electricity consumption data with emission factors that represent how electricity is generated.
At a high level, the calculation follows this relationship:
Scope 2 emissions = Electricity consumption × Electricity emission factor
Where each term depends on explicit methodological choices.
The calculation relies on three elements:
In practice, these choices determine which electricity production is considered to be associated with a given unit of consumption. While the calculation itself is simple, the resulting Scope 2 emissions can vary significantly depending on the selected time resolution and geographic scope.
To account for the specific characteristics of electricity systems, the GHG Protocol defines two distinct approaches for calculating Scope 2 emissions: the location-based method and the market-based method. Both quantify emissions from purchased electricity, but they rely on different assumptions about how electricity generation should be attributed to consumption.
The location-based approach reflects the average emissions intensity of the electricity grid from which electricity is consumed. Emission factors are typically based on regional or national electricity mixes and represent the physical generation of electricity on the grid over a given period. Under this approach, Scope 2 emissions primarily depend on where electricity is consumed and on the characteristics of the local power system.
The market-based approach reflects emissions associated with specific electricity procurement choices. It relies on emission factors derived from contractual instruments such as power purchase agreements, guarantees of origin, or renewable energy certificates, provided they meet defined quality criteria. Under this approach, Scope 2 emissions depend on how electricity is sourced contractually, rather than on the average grid mix alone.
Both approaches are reported separately because they answer different questions. The location-based method provides insight into an organization’s exposure to the carbon intensity of the local electricity system, while the market-based method reflects procurement strategies and sourcing claims.
Neither approach fully captures the operational dynamics of electricity systems on its own. The distinction between location-based and market-based Scope 2 highlights a deeper structural issue: electricity emissions are shaped both by physical grid conditions and by contractual and market mechanisms, which do not always align. As electricity systems become more variable, more local, and more constrained, this gap between accounting frameworks and system reality is becoming increasingly visible.
In practice, location-based Scope 2 reflects the carbon intensity of the electricity system where consumption occurs, while market-based Scope 2 reflects contractual sourcing choices.
Scope 2 accounting was originally designed for electricity systems that were relatively stable, centralized, and predictable. In such contexts, annual or regional average emission factors provided a reasonable approximation of the emissions associated with electricity consumption.
This context is changing. Electricity generation is becoming more variable due to the growing share of renewable energy sources whose output depends on weather and time of day. At the same time, electricity systems are becoming more spatially differentiated, with local grid constraints and congestion playing a larger role in how electricity is produced and delivered.
As a result, the carbon intensity of electricity is no longer constant over time or uniform across locations. The emissions associated with consuming one kilowatt-hour of electricity can vary significantly depending on when and where it is used. Yet traditional Scope 2 accounting approaches often smooth out this variability by relying on aggregated emission factors.
This growing mismatch between accounting averages and system reality affects how organizations interpret their electricity-related emissions and how they assess the impact of operational or procurement decisions. The evolution of Scope 2 methodologies reflects this tension, as frameworks adapt to better capture the temporal and geographic dimensions of electricity production.
For many organizations, Scope 2 has long been treated primarily as a reporting requirement: a figure to disclose annually, often calculated after the fact and with limited connection to operational decisions.
As electricity systems evolve, this separation is becoming harder to maintain. Because electricity-related emissions depend on when and where electricity is consumed, Scope 2 increasingly reflects operational realities rather than static averages. For large electricity consumers in particular, consumption patterns, scheduling choices, and procurement strategies all influence how Scope 2 emissions materialize in practice.
Scope 2 accounting does not prescribe specific actions. Its role remains to quantify and report emissions. However, by making the link between electricity use and power system conditions more visible, it is increasingly shaping how organizations interpret their emissions data, assess trade-offs, and anticipate future constraints on electricity systems.
