SBTi V2.0 updates: What new rules mean for renewable energy reporting

Separating scope 1 and scope 2 targets creates more accountability by preventing progress in one scope from masking deficits in the other. For energy teams managing large EAC portfolios, this underscores the need for a dedicated scope 2 strategy that connects electricity demand, procurement instruments, and reported results to a defined pathway.

Near-term scope 2 targets for large electricity consumers must cover 100% of emissions, rather than a selected set of priority sites. Companies forecasting average annual electricity consumption growth above 20% over the target period must also set a scope 2 emissions-reduction target; a low-carbon electricity percentage target alone is insufficient. This requirement is especially relevant for companies adding data centers, manufacturing capacity, electric vehicle fleets, or other large loads.

Meeting these data and reporting requirements demands close coordination across sustainability, energy, procurement, facilities, finance, and legal teams. These groups need shared portfolio visibility, clear ownership, and consistent documentation of how procurement supports the company’s scope 2 target.

V2.0 introduces more specific geographic matching rules. Companies must generally match electricity use with low-carbon electricity from the same deliverability region. In the United States, this may mean shifting from one U.S. coverage calculation to between five and twenty regional calculations, depending on the boundaries applied.  

This expansion has real operational consequences. A company previously tracking a single U.S. renewable energy balance may now need separate supply-and-demand calculations for each relevant region, along with documentation showing that each renewable instrument is eligible for the load it serves. A portfolio that appears 100% covered nationally may still have regional shortfalls because surplus EACs in one market cannot offset deficits in another.

To manage this effectively, energy teams must connect:

• Facility-or market-level electricity demand
• EAC supply by geography, vintage, technology, and certification
• PPA generation and certificate delivery
• Utility- or supplier-delivered renewable electricity
• The matching rules associated with each reporting framework

Geographic matching and hourly reporting are related but distinct. Geographic matching asks where low-carbon electricity comes from; hourly accounting asks when it was generated relative to consumption. For large electricity consumers, V2.0 requires reporting of hourly matching performance in significant regions, or activity pools, but it does not require companies to adopt an hourly matching target.

The change in data granularity is significant. A single annual consumption value becomes 8,760 hourly load values each year, even before generation and certificate data are added. For a company with 10 significant activity pools, that translates to at least 87,600 region-hour load calculations annually. Pairing loads with generation data—while also accounting for time zones, daylight-saving changes, contract allocations, missing intervals, and corrections—adds further complexity to an already data-intensive process.

The immediate goal is to understand data readiness:

• Which sites or loads fall within the reporting requirement?
• What interval data is available today?
• Can existing contracts and instruments be connected to the correct hours?
• Where are the material gaps in data, coverage, or internal ownership?

V2.0 also introduces third-party assurance of end-of-cycle progress. Large companies must be able to trace reported results, including their hourly matching percentage, to source data, methodologies, and instrument allocations.

Annual reporting and recurring five-year target cycles make assurance readiness an ongoing requirement. Teams must maintain current portfolio data, attribution rules, and decision records instead of reconstructing evidence before a review. 

Because this information often sits across contracts, registries, invoices, and supplier reports, companies need a system of record that connects electricity demand, instrument allocation, and retirement. This makes assurance-ready reporting a continuous output of the workflow.

The new standard strengthens traceability requirements for EACs used toward targets. Certificates must be issued, transferred, and retired through secure, transparent tracking systems that prevent double counting. The registry or equivalent system must record the certificate’s full lifecycle, including issuance, transfer, redemption, cancellation, and retirement.

The transaction volume alone can be substantial. In North America, a company matching 100GWh of annual consumption may need to track up to 100,000 one-MWh RECs, often managed in batches, alongside records from PPAs and supplier products. Those certificates must be allocated to the appropriate loads and reporting periods.

Retirement alone does not establish eligibility. Each certificate must meet the applicable deliverability, timing, and other eligibility requirements. Deliverability determines whether the generation attributes can be matched to a particular load; it does not change the underlying act of retirement. Managing these requirements across markets and registries calls for portfolio-level controls that connect procurement, allocation, retirement, consumption, and reporting.