How Far Has the Revision Process Progressed?

The GHG Protocol, widely used to calculate corporate greenhouse gas emissions, is revising an interconnected suite of standards and guidance, including the Corporate Standard, Scope 2 Guidance, Scope 3 Standard, and Actions and Market Instruments (AMI). The process reflects growing concern that the 2004 Corporate Standard, the 2011 Scope 3 Standard, and the 2015 Scope 2 Guidance have not kept pace with subsequent developments in net-zero targets, mandatory sustainability disclosure, renewable energy certificate markets, and granular electricity data. In particular, critics have questioned how accurately corporate disclosures reflect genuine contributions to grid decarbonization and whether procurement methods marketed under the same “100% renewable” label can have markedly different climate impacts.

The proposed revisions are not determined by the Secretariat alone. Technical issues are considered by expert Technical Working Groups (TWGs), while the Independent Standards Board (ISB) decides whether proposals should proceed to public consultation and whether final drafts should be approved. The Steering Committee (SC) provides overall strategy and oversight. In 2025, the GHG Protocol also announced collaboration with the International Organization for Standardization (ISO), setting a direction toward jointly developing an integrated corporate standard that aligns the GHG Protocol with ISO 14064-1. The revision may therefore extend well beyond an update to a single guidance document, potentially influencing future statutory disclosure, target validation by initiatives such as the SBTi, investor assessments, and supplier procurement requirements.

The Scope 2 consultation attracted support for greater accuracy, but also substantial concern about implementation, including the availability of hourly data, burdens on developing countries and smaller companies, treatment of existing PPAs, and reduced liquidity in certificate markets. The final standard is therefore likely to turn not only on principles, but also on exemptions, estimation using load profiles, legacy provisions protecting existing contracts, and phased implementation over several years. The lesson for companies is not to wait for the final wording. Unless they begin organizing 30-minute and hourly demand data and inventorying the generation source, time of generation, location, certificate ownership, and expiry dates of existing contracts, they may struggle to comply even if a transition period is provided.

The Scope 2 public consultation ran from October 20, 2025, through January 31, 2026, and a summary of feedback was published in July 2026. Meanwhile, the substance and timetable of the integrated standard, including Scope 3, remain under review. The timeline below therefore distinguishes completed milestones from plans announced at the time; future dates and effective dates remain subject to change.

The Core of the Scope 2 Proposal: Electricity Procurement Defined by “When” and “Where”

The revision with the most direct potential impact on the valuation of geothermal power concerns Scope 2: indirect emissions from purchased or acquired electricity, steam, heat, and cooling. Current guidance requires companies to report both a location-based figure, using average grid emission factors, and a market-based figure reflecting procurement choices such as contracts and certificates. The proposal retains this dual-reporting framework. The central issue, however, is that under the market-based method a company may report zero emissions when annual electricity consumption matches the annual volume of renewable attributes, even if generation and consumption occur at different times. When daytime solar attributes offset nighttime demand from a data center, the accounting result may be zero even though LNG- or coal-fired plants are operating on the grid at night. Hourly Matching and Deliverability are intended to narrow this gap between “decarbonization in reporting” and decarbonization of the physical power system.

① Hourly Matching

• Location-based method: The proposal establishes a hierarchy favoring the most granular emission factors available, with greater temporal and geographic precision. Where hourly factors are available, they can distinguish solar-rich daytime periods from evenings and nights when reliance on thermal generation rises. Reliable hourly factors are not publicly available in every country or region, however. The proposal also considers how to define “accessible data” and use proxy data; it is not a simple requirement for every company to produce complete hourly factors immediately. For Japanese companies, the challenge will be to connect area-level supply-and-demand data from general transmission and distribution utilities, retailers’ emission factors, and site-level smart-meter data—and retain them as auditable calculation evidence.
• Market-based method: The public draft proposes matching electricity consumption with energy attribute certificates (EACs) on an hourly basis. The concept is to measure how much demand in each hour is covered by eligible attributes generated in that same hour. Hours with insufficient attributes would be assigned emissions using a prescribed factor, such as the residual mix. Consequently, Scope 2 would not reach zero if many nighttime or winter hours remained unmatched, even when the annual renewable volume was sufficient. In practice, this requires end-to-end data controls covering timestamps for demand and generation, metering intervals, time zones, certificate retirement, treatment of missing data, and third-party assurance. Thresholds for small organizations, standard load profiles, transition arrangements for existing contracts, and phased implementation have also been proposed, making the balance between accuracy and feasibility a central issue for the final standard.

If adopted, this framework would shift procurement assessment away from annual unit cost toward the ability to reduce unmatched hours. Solar power can effectively serve daytime load, but covering residual demand after sunset will require a portfolio combining resources such as wind, hydropower, geothermal, nuclear, battery storage, and demand response.

Geothermal power is particularly valuable here as a source capable of serving baseload demand, owing to its high capacity factor and predictable output. Because scheduled maintenance and fluctuations in steam supply can cause outages, a geothermal plant’s capacity factor cannot simply be treated as its 24/7 achievement rate. Yet overlaying a customer’s load curve with actual generation data and simulating the hours in which shortfalls arise can reveal the value of including geothermal generation in the procurement portfolio.

② Deliverability: Market Boundaries and Physical Deliverability

Deliverability asks whether generated electricity lies within a geographic and market framework from which it could, in electrical and institutional terms, reach the point of consumption. Its purpose is to prevent companies from buying inexpensive certificates from regions effectively isolated by transmission constraints and then reporting zero emissions at the load location. The public draft does not necessarily require the physical tracing of electrons in every hour. Instead, it explores approaches under which Deliverability could be demonstrated through a defined market boundary, transmission capability, or other approved evidence. Physical PPAs would therefore not be the only eligible instrument, nor would virtual PPAs or certificate transactions automatically become ineligible. More important than contract form will be the ability to substantiate the generation location, load location, time, exclusivity of attributes, and relevant transmission constraints.

In Japan, the service territories of the general transmission and distribution utilities—Hokkaido, Tohoku, Tokyo, Chubu, Hokuriku, Kansai, Chugoku, Shikoku, and Kyushu—serve as basic units for electricity trading and system balancing. The nine JEPX areas have not, however, been formally established as GHG Protocol market boundaries. If area-based boundaries are referenced, applying geothermal or solar attributes from Kyushu to a Tokyo data center could raise questions about interconnector capacity, congestion, and rules for transferring attributes. Conversely, if a framework permits Deliverability to be demonstrated across a broader market, interregional transactions would not necessarily be excluded. Japan’s non-fossil certificate system can attach tracking information such as plant name and location, but Hourly Matching will require a data platform capable of verifying the time of generation as well. In 2026, a Japanese demonstration project was announced for a 24/7-ready PPA that matches demand with multiple non-fossil power sources on an hourly basis while maintaining tamper-evident records suitable for third-party verification. The race to implement the necessary technology has therefore already begun, even before the rules are finalized.

How Should Additionality Be Treated? Reading Scope 2 and AMI Separately

A critical point in discussing Additionality is to avoid conflating Scope 2 with the question of how much a company’s actions change economy-wide emissions. Scope 2 is an attributional accounting framework that allocates emissions associated with the energy a reporting company purchases and consumes according to defined rules. Additionality, by contrast, asks a counterfactual question: Would a power plant have been built without the PPA or certificate purchase? Did the procurement decision alter the operation of an existing facility or an investment decision? Did it actually displace higher-emitting generation on the grid? These are questions that AMI is intended to address. A low Scope 2 figure is therefore not synonymous with a large additional contribution to the climate.

The 2026 AMI white paper outlines a framework for transparently reporting several distinct statements—such as traceable procurement, additional interventions, and avoided emissions—separately from the corporate inventory. It is not yet a formal draft standard; a full public consultation draft is scheduled for 2027. Assessing Additionality will require attention to whether a facility is new or existing, contract duration, price guarantees, contribution to financing, public support, exclusivity of attributes, baseline setting, and the strength of causal evidence. Rather than assuming that all new generation is additional or all FIT-supported generation is non-additional, companies will need evidence showing the extent to which their contracts influenced project investment decisions or continued operation. The principal issues are as follows.

• Standard Supply Service: Standard renewable or effectively renewable retail offerings are easy to adopt, but they often make it difficult for customers to show which capacity additions or continued operations they enabled. Quality assessment will increasingly focus on whether the location, generation time, commissioning year, and certificate retirement can be verified and whether double counting against the residual mix is prevented.
• FIT/FIP generation: Because publicly supported facilities may have been built even without corporate demand, claims of Additionality require caution. At the same time, no final rule has been confirmed that would categorically exclude FIT/FIP generation from Scope 2. Assessment should instead consider the legal ownership of environmental attributes, revenue stabilization provided by corporate contracts, market risk borne under the FIP regime, and contributions to repowering or life extension.
• Non-Fossil Certificates: Certificates are essential for establishing ownership of environmental attributes and preventing double counting, but current annual vintages and product classifications may be insufficient to demonstrate Hourly Matching and Deliverability. A mechanism will be needed to link hourly demand data with tracking information identifying the plant, location, generation period, and technology. Certificates are unlikely to become unusable as a category; rather, the price gap may widen between those that meet enhanced quality requirements and those that do not.

In practice, the answer will not be to select a single “correct” product, but to assign complementary roles to multiple instruments. On-site solar directly reduces daytime demand, while off-site PPAs provide long-term price stability and source identification. Geothermal, hydropower, and wind can complement solar during weaker production periods, while batteries can shift surplus attributes to hours of demand. This requires clear treatment of the source attributes of stored power, charging and discharging losses, emissions associated with grid charging, and double use of certificates. Demand response can shift consumption away from high-emission hours and reduce unmatched volumes directly. A long-term PPA with a new project that does not depend on public support may make Additionality easier to demonstrate, but coherent implementation still requires the contract to address creditworthiness, tenor, price adjustment, shortfall remedies, regulatory change, and ownership of certificates.

The Scope 3 Revision: Strengthening Completeness and Data Quality

At first glance, revisions to Scope 3, which covers value-chain emissions, may appear less directly relevant to the electricity value of geothermal power than the Scope 2 changes. Yet when exploration, resource assessment, development, operations and maintenance, financing, and heat supply are taken into account, the revision could broadly affect disclosure practices for developers, customers, and financial institutions. A March 2026 progress document described Phase 1 deliberations on data quality, boundary setting, investments, and a possible new category for activities not captured by the existing 15 categories. The document itself states that it should not be relied upon as a final standard, so the points below should be read as an indication of the current direction of travel.

• Proposed 95% inclusion boundary: Working papers consider requiring all material Scope 3 emissions to be included in principle, with justified exclusions capped at 5% in aggregate. The aim is to prevent companies from arbitrarily omitting categories that are difficult to calculate. Geothermal developers would need to determine how much primary data they can obtain for steel, cement, drilling services, equipment transport, construction, waste, business travel, investments, and other sources.
• Greater visibility into data quality: One proposal would disaggregate Scope 3 emissions by data type, including supplier-specific data, activity data, and spend-based estimates. Assessment would therefore focus not only on total emissions but also on the extent to which calculations rely on measured and primary data. Procurement contracts may need to specify emissions-data provision, calculation methods, update frequency, and verification rights.
• Potential Category 16: A new category is being discussed to capture “other value-chain activities” and activities enabled by a company that do not fit within the existing 15 categories. This would not, however, automatically allow emissions avoided by customers through geothermal heat supply to be booked as negative Scope 3 emissions. Corporate inventories should remain separate from product comparisons, avoided emissions, and intervention impacts.
• Investments and financed emissions: For Category 15, boundaries and attribution methods are under consideration for equity, lending, funds, and project finance. Because geothermal projects involve substantial capital needs and risk during exploration and drilling, financial institutions will need to explain not only financed emissions, but also the effect of capital allocated to low-carbon infrastructure, project life-cycle emissions, and stranded-asset risk.
• Parallel disclosure of multiple metrics: Across the GHG Protocol, the direction is increasingly toward reporting corporate inventories, contractual attributes, offsets, avoided emissions, and other intervention impacts separately rather than blending them. Geothermal businesses can strengthen credibility by separately measuring plant life-cycle emissions, the attributes of low-carbon electricity supplied to customers, and emissions avoided across society—and by stating the boundaries and assumptions for each.

A commonly overlooked feature of geothermal Scope 3 emissions is that, although operating emissions may be low, substantial upstream emissions can arise from well drilling, casing, cement, steam pipelines, generation equipment, and long-distance transport. Boundaries with Scope 1 must also be checked for well testing and the treatment of non-condensable gases. Developers should incorporate the weight, origin, and recycled content of major materials; drilling-rig fuel; construction electricity; transport distances; equipment life; and well-abandonment measures into their data registers, while prioritizing the primary data to be obtained from EPC contractors and suppliers. This is more than a disclosure exercise: it creates a management foundation for identifying high-impact reduction measures, such as low-carbon steel, improved drilling efficiency, and equipment life extension.

Opportunities for Geothermal: Monetizing the Value of “24/7” Supply

If Hourly Matching and Deliverability are incorporated into the final standard, geothermal competitiveness will be assessed not only on whether the resource is renewable, but also on whether it can generate when electricity is needed. Geothermal can maintain comparatively stable output from evening into the night as solar generation falls, during periods of weak wind, and through pronounced seasonal fluctuations. This characteristic can serve customers’ baseload demand while reducing both unmatched hours and the storage capacity required across the portfolio. Geothermal is not immune to scheduled inspections, well decline, scale deposition, changes in steam composition, or grid outages. Its value should therefore be measured not by average capacity factor alone, but by hourly availability, forecast error, and the cost of replacement procurement during outages.

① Balance Development Near Demand Centers with Broader-Area Procurement

If the service territories of Japan’s general transmission and distribution utilities are used as market boundaries, transactions transferring geothermal value from Hokkaido or Kyushu to data centers in Tokyo may face additional conditions concerning interconnectors, congestion, and the audit trail for attribute transfers. Site assessment should therefore incorporate not only resource potential and drilling success probability, but also large loads within the same area, prospective demand from data centers and semiconductor plants, electrification demand, available grid connection capacity, curtailment risk, and interregional price differentials. High-quality geothermal resources, however, are geographically concentrated. Prioritizing proximity to demand alone could compromise resource quality or local acceptance. Developers should therefore compare multiple demand-creation strategies, including PPAs with customers in the same area, joint supply to multiple customers, broader-area transactions, and local uses such as heat supply or hydrogen production.

② Reduce Policy Dependence and Embed Time Value in Contracts

Monetizing geothermal’s time value will require PPAs to evolve from simple fixed-price energy contracts into services that guarantee time-specific quality. Contracts should define the covered generation assets and ownership of certificates, hourly matching targets, measurement and verification methods, replacement supply during planned and unplanned outages, settlement for underperformance, authority to aggregate batteries or other resources, and review mechanisms for regulatory change. Unbundling price into energy value, environmental value, time value, reliability, and data-verification services can help customers and lenders evaluate risk. The relevant comparison is not geothermal’s stand-alone cost, but the total cost of achieving the same hourly match rate using solar and storage alone, together with the cost of replacement electricity and certificates during unmatched hours.

Developers should begin with four preparations. First, compare the 30-minute or hourly load curves of prospective customers with actual and forecast plant output, and estimate the Hourly Matching rate, the longest unmatched interval, and replacement procurement volumes rather than relying on an annual renewable share. Second, link generation, demand, and certificate data under common identifiers and design audit trails, procedures for filling data gaps, and third-party assurance. Third, develop products premised not only on long-term PPAs with a single customer, but also on collaboration with aggregators, retailers, storage providers, and multiple generation sources. Fourth, absorb the risk of unsettled rules through change-in-law clauses and progressively tightening quality targets. The GHG Protocol revision is not yet complete, but the consultation proposal clearly points from annual volume toward time and location. It will not automatically create extraordinary demand for geothermal power. Yet developers that can substantiate stable output with data, reduce customers’ unmatched hours, and translate that benefit into contractual terms and pricing may be well positioned to capture added value in the emerging green electricity market.

References

1. Greenhouse Gas Protocol, “Public Consultation – Scope 2”, October 2025.
2. Greenhouse Gas Protocol, “Upcoming Scope 2 Public Consultation: Hourly Matching and Deliverability”, October 14, 2025.
3. Greenhouse Gas Protocol, “Feedback Opportunities” (consultation period for the Scope 2 public consultation and overview of the AMI request for information), accessed in 2026.
4. Greenhouse Gas Protocol, “Actions and Market Instruments Phase 1 Progress Update White Paper”, March 2026.
5. Greenhouse Gas Protocol, “Scope 3 Standard Revisions Phase 1 Progress Update”, March 2026.
6. Greenhouse Gas Protocol, “ISO and GHG Protocol Announce Strategic Partnership to Deliver Unified Global Standards for Greenhouse Gas Emissions Accounting”, September 9, 2025.
7. Greenhouse Gas Protocol, “GHG Protocol Announces Key Standard Development Updates”, July 29, 2026.
8. Electric Power Development Co., Ltd. and others, “Successful Demonstration Toward the Provision of a 24/7-Ready Corporate PPA,” April 17, 2026.
9. NTT Anode Energy Corporation and others, “Completion of a Demonstration Test of Hourly Matching Toward 24/7 Carbon-Free Electricity Supply,” February 12, 2026.