The Sustainable Aviation Fuel Cost Premium Is Permanent

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Key Takeaways

• Trust in carbon credits remains low. In part, this is because many mistakenly treat every credit type as interchangeable.
• Reduction, removal, and avoidance credits are verified against fundamentally different baselines, so credit quality must be judged based on type and project specifics, never with one blanket standard.
• The Integrity Council for the Voluntary Carbon Market's Core Carbon Principles now give buyers an independent bar to check against, including 44 methodologies approved across 13 eligible crediting programs, as of August 2026.
• Removal credits still make up only 5–6% of the market, even as compliance-driven demand accelerates, per our 2026 State of the Voluntary Carbon Market report.

Three Types of Carbon Credits: Reduction, Removal, and Avoidance

A carbon credit is a mechanism that allows one party to compensate another for their carbon mitigation activities. Based on their net emissions impact, there are three types of carbon credits: reduction, removal, and avoidance. 

1. Reduction credits reflect activities that decrease greenhouse gas emissions, compared to prior practices. 
2. Removal credits reflect activities that remove carbon dioxide already present in the atmosphere and oceans and lock it away for decades, centuries, or millennia.
3. Avoidance credits reflect activities that prevent greenhouse gases from being emitted in the first place. For all three types, credits are assessed and issued by measuring or estimating how much carbon is reduced, removed, or avoided as a result of a credit purchase and its associated activities.

While credits are assessed in different ways depending on the type, one of the most important indicators of quality is a project's baseline - the emissions that would be present in a business-as-usual scenario, without action being taken to reduce, remove, or avoid them. Project developers use baselines as a means of comparison to assess the net emissions impact of a project. 

• Baselines must be accurately set and data-driven. 
• Emissions impacts of a project must be correctly calculated against its baseline. 

Reduction, removal, and avoidance projects involve very different activities and, for some types of projects, it may be more challenging to establish an accurate baseline. However, without accurate baselines, climate impacts cannot be reliably determined.

Across the voluntary carbon market, Reduction credits represent roughly 20% of the purchases. Removal credits represent roughly 5% of the purchases. The remainder, roughly 75%, are avoidance credits.

Carbon Reduction Credits

Carbon reduction must drive the majority of our push to net zero, but translating carbon reduction activities into carbon credits that can be purchased is challenging. Examples of activities represented by carbon reduction credits include reducing fossil fuel use by improving fuel efficiency, or programs that reduce the methane that is generated from farms or municipal waste processing. 

Reduction credits are measured and quantified against the baseline emissions of an existing technology or process. Some reduction credits are easy to track and measure, such as efficiency investments or destruction of fugitive methane. Other projects are more complex. For example, low-emission cookstove projects in developing regions rely on tracking patterns of cookstove use and quantifying emission factors for various fuel and stove combinations, both of which are hard to do. The result, as studies have shown, sometimes leads to overcrediting in reduction projects. 

Superpollutant Credits

One class of reduction credit, superpollutant credits, has garnered recent attention. These credits involve the reduction of non-CO2 greenhouse gases with very strong radiative forcing, such as methane, nitrous oxides, or fluorinated gases like chlorofluorocarbons. These are not a substitute for CO2 removal, but can provide rapid and profound reductions at modest cost. Many different kinds of superpollutants exist in today’s market, worth roughly $60M today. Recent purchases by tech companies and others have highlighted the potential of these reduction credits.

Another class of reduction credit, transition credits, involves the deliberate early closure of emitting assets like coal-fired power plants or heavy manufacturing facilities. Early efforts by governments, banks, and companies around the world under the Just Energy Transition Partnership agreement jump-started transition credits as a concept at COP26. The Kinetic Coalition, in partnership with many groups including Relae, has launched work to bring transition credits to market with several pilot efforts, including closing a coal plant in the Philippines 10 years early. 

Carbon Removal Credits

Projects that remove carbon come from a diverse set of solutions, from nature-based solutions like reforestation, to hybrid solutions like biochar, to engineered solutions such as direct air capture and storage. Roughly 5–6% of credits on the voluntary carbon market today are classified as removals, up from roughly 3% a few years ago.

Carbon removal baselines are determined differently depending on whether a project uses an engineered, hybrid, or nature-based solution. For engineered removals, the baseline is zero, because no carbon removal was occurring in the absence of the project. The credited removal will be the difference between the quantity of carbon removed and any emissions that occur to facilitate the removal (determined through a carbon credit life cycle assessment). Baselines for hybrid and nature-based removals can be more challenging. In natural systems, changes in carbon stocks created by removals must be measured and approximated over time, and creditable removals represent the additional carbon removed by the intervention relative to the baseline (e.g., fallow land versus a reforestation project).

Another important consideration for carbon removal credits is project durability, a measure of the likely duration of carbon storage. Stored carbon can re-enter the atmosphere either through deliberate actions (e.g., deforestation) or accidental ones (e.g., wildfires). Nature-based removals are especially vulnerable to being re-released and are usually considered less durable (i.e., stored for less than 50 years). In contrast, engineered solutions offer high durability (i.e., stored for hundreds to thousands of years), and hybrid removals also offer durability periods that are typically longer than those of nature-based removals.

While less durable, nature-based solutions are effective, cost-effective, and widely available today. They made up over 95% of all carbon removal credits issued in 2025. Engineered and hybrid solutions are more expensive and scarce but offer longer durability. Prices of engineered carbon removal are likely to fall with innovation and increased market participation, but are currently much higher than most nature-based credits. With SBTi's finalized Corporate Net-Zero Standard V2.0, this balance is likely to shift. Large companies must now purchase removal credits covering 1–100% of scope 1, scope 2, and scope 3 emissions between 2035 and their net-zero year, with an explicit focus on more durable CO2 removal credits.

Carbon Avoidance Credits

Examples of carbon avoidance include avoiding deforestation that would result in the release of carbon dioxide into the atmosphere or clean energy projects that avoid the release of emissions from burning fossil fuels in possible facilities. This can be confusing, since many avoided credits are called reduction credits, as is the case with projects under the Reducing Emissions from Deforestation and Forest Degradation (REDD+) framework. Avoidance credits make up roughly 75% of certified credits on the voluntary carbon market today - an overwhelming majority - in part due to high availability and low price. 

Avoiding emissions is an important goal with numerous environmental, climate, community, and other benefits. Relae works with clients and customers across industries on developing and implementing strategies to avoid emissions within their value chain. However, there are significant challenges with the way that many carbon avoidance credits are created.

• Carbon avoidance credits are based on an estimate of the emissions that might have existed had a project not been funded. Because it is impossible to observe what might have happened in the absence of a project, carbon avoidance estimates are determined by considering historic data and contextual information. Statistical models can be used to create a presumed baseline that represents what would have happened in the absence of the project.

• Because the baseline is not observed in an avoided emissions project, there is uncertainty in calculating the number of carbon credits it produces. If the baseline is not set accurately, a project can overcredit. While the lack of a directly observed and measured baseline means avoidance credits will always have some degree of uncertainty, high-quality avoidance projects present compelling evidence to support their baselines, greatly reducing uncertainty. 

New datasets, statistical techniques, and methodologies are providing opportunities for developing avoidance credits with more certainty. Three REDD+ methodologies have now cleared the Integrity Council for the Voluntary Carbon Market (ICVCM) assessment for its Core Carbon Principles (CCPs), a concrete sign that credit quality standards for avoidance projects are maturing.

Defining and Standardizing Quality in the Voluntary Carbon Market

Carbon credits are intended to reduce, remove, or avoid emissions. They pay for an environmental service that must be delivered. Companies working to generate climate benefits through credit purchases must grapple with the differences and uncertainties of credit quality to ensure that the intended benefits are realized. 

While high-quality credits exist for all types of projects, a rich understanding of the differences in methodologies, geographies, physics, and ecology is required to identify high-quality projects and understand varied certainty, durability, and risk terms. Identifying high-quality carbon projects demands extensive and project-specific diligence beyond carbon market certification.

Our own diligence work reveals that high-quality projects can be hard to find. Fewer than 10% of the carbon removal projects we assessed for our 2026 State of the Voluntary Carbon Market report met our quality criteria. This diligence work now has an additional, independent backstop. As of August 2026, the ICVCM has approved 44 methodologies across 13 programs, as eligible for its CCP label, including ACR, Gold Standard, and VCS. For buyers, considering projects that are CCP-eligible should be used as a first filter—not a substitute for project-level diligence, but representing a legitimate floor.

While realized emissions impacts may be difficult to prove in some cases, it is important to remember that some projects provide additional co-benefits. REDD+ projects, for example, may have a positive impact on conservation and biodiversity, and cookstove projects may offer clear human health and social welfare benefits. However, these benefits should be assessed separately from carbon reduction, removal, or avoidance benefits.

Frequently Asked Questions

What's the difference between a carbon credit and a carbon offset? 

A carbon credit represents one verified tonne of emissions reduced, removed, or avoided. A  carbon offset describes how a buyer uses that credit, typically to counterbalance emissions it has not yet accounted for. The credit itself does not change type based on how it's claimed.

Which type of carbon credit—reduction, removal, or avoidance—is highest quality? 

No single type is inherently highest quality. Each project, regardless of type, is verified against a defined baseline. Quality depends on how rigorously that specific baseline was set and how well the project meets other quality criteria. Removal credits from engineered sources have the most straightforward baseline (zero), and avoidance credits carry the most baseline uncertainty by design, but these are only one determinant of credit quality.

Do carbon removal credits automatically meet the ICVCM’s Core Carbon Principles? 

No. The ICVCM assesses methodologies and programs, not individual projects. If a project uses a methodology that is eligible for the CCP label, this can be a useful floor but is not a guarantee of high quality.

How does SBTi's near-term removal mandate change which credits I should buy now?

SBTi's finalized Corporate Net-Zero Standard V2.0 doesn't require removal purchases until 2035, but it sets the ramp now (i.e., 1% of scope 1, scope 2, and scope 3 emissions in 2035, scaling to 100% by the net-zero year). This means the highest-durability removal supply that is scarcest and most in demand today is the same supply that many companies will need later. The SBTi guidelines are still changing, so buyers and project developers must track them closely.

Key Takeaways

• Buyers have been navigating the low-carbon fuels (LCF) market without a map.  The LCF market is expanding rapidly, but standards, definitions, and quality claims vary widely across regions, certification schemes, and regulatory systems, leaving voluntary buyers without a holistic framework for evaluating what they procure.
• Certifications cover some of the picture, not all of it. Existing certification schemes provide valuable assurance but vary in scope and rigor, and few, if any, were designed specifically with voluntary market buyers in mind. 
• The 2026 criteria give buyers a legible quality framework. The 2026 Criteria for High-Quality Low Carbon Fuels bring together key sustainability considerations across six principles, including social and environmental integrity, carbon accounting, additionality, feedstock sourcing, and leakage, giving buyers and producers a legible, living framework to navigate procurement decisions with confidence.

Verifying Quality Is Challenging in the Current Low-Carbon Fuels Market

For airlines, logistics companies, and large corporations with hard-to-abate transportation emissions, low-carbon fuels (LCFs) have become an important part of the decarbonization toolkit. Yet it remains difficult for procurement teams to answer a fundamental question: what does high-quality procurement actually look like? 

Standards, definitions, and sustainability claims vary widely across regions, certification bodies, and regulatory programs. The result is a market where quality is difficult to verify, certifications are difficult to compare, and the gap between a fuel's claims and its actual sustainability profile can be hard to close. Sustainable production will be especially critical as the market scales, because low-carbon fuel systems are deeply embedded in land, agriculture, forestry, and communities. 

The 2026 Criteria for High-Quality Low Carbon Fuels are designed to close this gap, giving voluntary buyers a consistent framework to evaluate the quality of what they procure and identify where additional diligence is still needed.

What Is a Low-Carbon Fuel?

For the purposes of the criteria, a low-carbon fuel, or LCF, is defined as a fuel or energy source whose lifecycle greenhouse gas (GHG) emissions are lower than those of a relevant, use-case-specific fossil fuel alternative. In this case, we are referring to the physical biofuel and its associated environmental attributes. 

While LCFs may be produced through biological, synthetic, or other non-fossil pathways, the 2026 edition focuses on biofuels for transportation, which currently represent the majority of LCF production and use. 

Understanding the Complex LCF Regulatory and Certification Landscape

The LCF market sits at the intersection of multiple regulatory and voluntary markets. In the US, this includes compliance programs such as the Renewable Fuel Standard (RFS) and state-level Low Carbon Fuel Standards (LCFS). Europe, the United Kingdom, Canada, and many other nations host comparable programs, often with specialized regulatory regimes for various transport sectors, e.g., aviation or maritime. 

These regulatory markets coincide with and often intersect voluntary markets, which contain a multitude of standards and certifications. For producers, this creates a complex landscape of market options. For buyers, it creates a signal problem: a fuel may carry one or more certifications, comply with one or more regulatory programs, and still leave meaningful sustainability questions unaddressed.

Several organizations, including the Roundtable on Sustainable Biomaterials (RSB) and the International Sustainability and Carbon Certification (ISCC), have developed widely used standards for LCFs. These certifications assess supply chains from feedstock to end use and provide important baseline assurance. 

However, they were developed with different primary audiences in mind and can vary in scope and rigor. Few existing schemes were designed to serve as a comprehensive sustainability reference for voluntary market buyers evaluating what a given fuel's certification covers and where gaps may still exist.

Simplifying High-Quality Procurement for Voluntary Buyers 

The 2026 Criteria for High-Quality Low Carbon Fuels are not designed to replace or compete with existing certification schemes. Rather, they consolidate key sustainability considerations from across the landscape of existing frameworks into a single, legible reference built specifically for voluntary market decision-makers.

The criteria apply across the full LCF supply chain, covering not only fuel producers but also fuel blenders, aggregators, and certificate traders. This LCF systems view encompasses the full set of production, certification, and procurement arrangements through which LCFs are generated and claimed. This reflects the reality that sustainability outcomes in this market are shaped by many actors, not just at the point of production.

The criteria distinguish between requirements that must be met (minimum thresholds for quality and integrity) and considerations that should be addressed, reflecting best practices and aspirational standards. This distinction is intentional: the criteria set a floor while leaving room for market participants to demonstrate quality in ways appropriate to their specific context. 

The criteria are organized around six core principles that together define what high-quality LCF production and procurement looks like. 

Six Principles for Procuring High-Quality Low-Carbon Fuels

1. Social harms, benefits, and environmental justice: preventing new harms to communities, reducing existing ones, and ensuring equitable distribution of benefits
2. Environmental harms and benefits: minimizing impacts on air, soil, water, and biodiversity
3. Carbon accounting: accurately quantifying lifecycle GHG emissions using credible methodologies and tracking environmental attributes to prevent double-counting
4. Additionality: demonstrating that voluntary market support enables outcomes that would not otherwise occur
5. Feedstock sourcing: ensuring responsible and equitable sourcing practices and requiring end-to-end chain-of-custody documentation traceable to the point of generation
6. Leakage: assessing and mitigating activity-shifting and market leakage associated with the LCF system

Where a fuel's existing certification or regulatory program adherence already addresses one or more of these core principles, that coverage should be disclosed to the buyer by the producer. Buyers can then use the criteria to identify where certification coverage aligns with quality expectations, and where supplemental diligence is needed.

A Living Framework for a Market in Motion  

The LCF market will continue to evolve as policy frameworks are shifting, certification systems are maturing, and new production pathways are emerging. The 2026 edition reflects the current state of the LCF market and is intended as a living resource, with future updates possible as the market develops and new science emerges. Future editions may expand to cover synthetic LCF pathways, renewable natural gas, and sector-specific considerations such as maritime fuels.

For buyers navigating voluntary LCF procurement, the criteria offer a practical starting point: a framework to evaluate what existing certifications cover, identify where additional diligence is needed, and build procurement decisions on a consistent quality foundation. For producers, they provide clear guidance on what a sustainability demonstration looks like for voluntary market buyers.

Read the 2026 Criteria for High-Quality Low Carbon Fuels to learn more about how the criteria apply to your procurement strategy or production system.

Frequently Asked Questions

What is a low-carbon fuel?
A low-carbon fuel is a fuel whose lifecycle greenhouse gas emissions are lower than a comparable fossil fuel alternative for the same use case. The 2026 LCF Criteria focus specifically on biofuels for transportation, which currently make up most LCF production and use.

What do the 2026 Criteria for High-Quality Low Carbon Fuels cover?
The criteria are organized around six principles: social harms, benefits, and environmental justice; environmental harms and benefits; carbon accounting; additionality; feedstock sourcing; and leakage. Together they give buyers and producers a consistent way to evaluate what high-quality LCF production and procurement looks like.

Do the LCF criteria replace existing certifications like RSB or ISCC?
No. The criteria aren't designed to replace or compete with existing certification schemes such as the Roundtable on Sustainable Biomaterials (RSB) or the International Sustainability and Carbon Certification (ISCC). Instead, they consolidate key sustainability considerations from across those frameworks into a single reference so buyers can see what their certification already covers and where supplemental diligence may be needed.

Who do the LCF criteria apply to across the supply chain?
The criteria apply across the full LCF supply chain, not just producers, but also feedstock suppliers, fuel blenders, aggregators, and certificate traders, reflecting that sustainability outcomes are shaped by many actors, not only the producer.

What's the difference between the "must" and "should" requirements in the LCF criteria?
"Must" requirements set minimum thresholds for quality and integrity that need to be met, while "should" considerations reflect best practices and aspirational standards market participants can work toward. This sets a floor while leaving room for participants to demonstrate quality in ways suited to their specific context.

Key Takeaways

• CORSIA, the program intended to address international aviation emissions, is currently the world’s largest international compliance carbon market, with approximately 200 million tonnes of eligible emissions units (EEUs) expected to be retired for Phase 1 (2024-2026) compliance. 
• Airlines have already begun retiring significant volumes of credits (clean cookstoves and jurisdictional REDD+) toward their Phase 1 obligations ahead of the January 2028 compliance deadline, signaling that the industry is treating CORSIA as a binding policy mandate.
• In addition to the four already approved, a record 25 carbon standards have applied for eligibility to supply credits under Phase 2 (2027–2035), pointing to a diversifying pipeline of credits.
• Legal enforcement of CORSIA at the national level remains uneven. A handful of jurisdictions, including the EU, Japan, Brazil, New Zealand, and Canada, have established compliance regimes, but it is unclear whether other major aviation markets will implement domestic enforcement requirements by 2027.
• As CORSIA matures alongside other compliance and voluntary frameworks, strategic engagement increasingly depends on understanding where eligibility overlaps and where the most value can be found.

Introduction to CORSIA 

The Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA) was established and is managed by the International Civil Aviation Organization (ICAO)—a specialized agency of the UN—and provides a compliance mechanism to reduce emissions from international aviation that do not fall within a single country’s contributions to the Paris Agreement. For years, CORSIA generated more commentary than activity—airlines weren’t required to offset a single tonne of CO₂ emissions (tCO₂) during the pilot phase (2021–2023). That is changing; in early 2026, Singapore Airlines and Japan Airlines retired significant volumes of carbon credits against their Phase 1 (2024–2026) obligations. Increasing authorization announcements showcase the eligible supply steadily entering the market, and 25 carbon standards have applied for Phase 2 (2027–2035) eligibility. As CORSIA becomes an active compliance market, this article explains how the program works, what is driving the current trends, and what to watch as Phase 1 draws to a close.

Who is Covered by CORSIA Phase 1 and Phase 2?

Because emissions from international aviation are not tied to any individual nation, the International Civil Aviation Organization (ICAO) adopted CORSIA in 2016 to complement the Paris Agreement framework and address these emissions. CORSIA applies to international airlines operating flights registered between participating countries. 

• During Phase 1, offsetting obligations apply only to routes between the 130 countries that have voluntarily opted in. 
• From Phase 2, participation becomes mandatory for all 193 ICAO member states, except for those below the aviation activity threshold or classified as Least Developed Countries, Small Island Developing States,  or Landlocked Developing Countries—although they can voluntarily participate. 

Several major aviation markets, including China, that are not participating in Phase 1 will be required to do so from 2027. 

Offsetting Obligations

Airlines are required to offset the portion of their emissions that exceeds the program’s baseline on routes subject to offsetting. The key input is the annual Sectoral Growth Factor (SGF), which reflects how much annual emissions on covered routes have grown above the baseline (set at 85% of 2019 emissions). In simple terms, each airline's offsetting obligation is calculated by multiplying its CORSIA-regulated emissions by the SGF.

For example, an airline that emits 1 million tCO₂ on covered routes in a year when the SGF is 10%, would have an offsetting obligation of 100,000 tCO₂. An airline that emits 500,000 tCO₂ in the same year would have an obligation of 50,000 tCO₂. The actual 2024 SGF was 15.4%, exceeding the baseline and triggering offsetting obligations for the first time since the COVID-induced reduction in international aviation activity. 

Beginning in 2033, CORSIA’s offsetting formula combined the SGF with an individual component that accounts for each airline's own emissions growth. The individual weighting starts at 15% in 2033 (with an SGF weighting of 85%) and rises to 45% by 2035 (SGF 55%). This progressively ties each airline’s obligations to its own emissions trajectory rather than sector-wide trends alone.

Airlines can also reduce their obligations by reporting the use of CORSIA Eligible Fuel (CEF). In order to qualify as CEF, Sustainable Aviation Fuel (SAF) must meet ICAO’s certification criteria. Offsetting remains a lower-cost option than sustainable fuel procurement, and CORSIA obligations are currently not influential drivers of CEF/SAF uptake compared to supply mandates, such as ReFuelEU Aviation. However, these dynamics will evolve as CORSIA matures and SAF prices continue to fall. 

CORSIA Eligible Carbon Credits: Phase 1 and Phase 2 

To determine the eligibility of carbon crediting standards and credits issued under those standards, ICAO's Technical Advisory Body (TAB) reviews applications and recommends approval to the ICAO Council, subject to restrictions on methodologies, vintages, and more granular project elements. Currently, no standard is approved without exclusions. Credits eligible for use under CORSIA are known as Eligible Emissions Units (EEUs).

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TAB broadly excludes some project types across standards, including large-scale grid-connected renewable energy projects and most project-level REDD+ activities. The exclusions reflect TAB's assessments of baselines, safeguards, and quantification gaps. However, these assessments are not static; ICAO updates its determinations as the evidence base improves. For example, in 2025, TAB approved certain direct air capture (DAC) and biochar pathways for the first time.

A record 25 carbon standards—certifying projects from emissions avoidance to engineered carbon dioxide removal (CDR)—have applied for Phase 2 eligibility in the 2026 assessment cycle, reflecting the scale of the opportunity. The International Air Transportation Association (IATA) projected a demand of 170–236 million EEUs for Phase 1 alone; developers are eager to serve this growing market. Assessment results are expected in October 2026.

Article 6 and Corresponding Adjustments

The biggest bottleneck for eligible supply has been requirements relating to Article 6.2 of the Paris Agreement. CORSIA requires that EEUs carry a host country Letter of Authorization (LoA) confirming that the host country will not count the underlying mitigation toward its Nationally Determined Contribution (NDC). This prevents double counting between CORSIA and national emission inventories, but it also means eligible supply depends on host country authorization, not just meeting methodological requirements. Authorized credits are called Internationally Transferred Mitigation Outcomes (ITMOs). 

To manage the risk that a host country fails to apply the promised corresponding adjustment, projects must secure legally enforceable insurance policies that either provide replacement EEUs or funds to secure them. Several providers have been approved to insure EEUs registered by Gold Standard and Verra. 

Insurance requirements do not apply when the host country has already confirmed the corresponding adjustments in its mandatory Paris Agreement reporting. For example, in March 2026, Madagascar submitted a Biennial Transparency Report (BTR) and annual information report that reflect the application of corresponding adjustments to CORSIA-eligible clean cookstoves credits listed on the Verra registry. According to Verra, BTR accounting is the “highest level of assurance” that ITMOs will not be double counted. 

The Enforcement Challenge

With the authorization bottleneck loosening, market attention is turning to demand. Critically, ICAO has no direct enforcement power; for CORSIA to work, participating countries must pass laws requiring airlines to comply with its requirements. Under CORSIA rules, airlines must retire their Phase 1 EEUs by January 2028, but most are not yet subject to legal sanctions for failing to comply. Where regulations do exist, it remains unclear whether penalties will be stringent enough to matter, or whether they will be enforced at all.

Where legal enforcement of offsetting requirements does exist, it varies by design. For example, in Brazil, failure to comply attracts a penalty of BRL 50/tCO₂ (US$10/tCO₂) and an administrative fine. Meanwhile, the Canadian Aviation Regulations impose administrative fines capped at CAD 25,000 (US$18,000) per infraction, but there is no specific fine for each tCO₂ not offset. However, the absence of a statutory penalty framework does not necessarily mean compliance will not be enforced. For example, New Zealand manages CORSIA participation through an administrative Memorandum of Understanding with Air New Zealand, rather than a dedicated legal regime (though this will change from 2027). Similar informal arrangements may be more common than the legislative record suggests.

According to 2024 data, US-based airlines account for around 15% of CORSIA-covered emissions. However, there is no indication that the federal government will implement CORSIA penalties under the current administration. It is unclear how non-compliance by a major economy will impact market confidence or enforcement by other governments, but uncertainty about US participation in multilateral climate programs is not new. 

What to Watch

• Global enforcement: As Phase 2 approaches, the prospects for CORSIA enforcement in key aviation markets will become clearer. China, which has not participated in the voluntary phase and has raised objections to CORSIA’s design on grounds of fairness, presents an uncertain picture for domestic transposition. The UK government has consulted on a draft legal amendment that would penalise non-compliance for UK airlines at £100/tCO₂ (US$130/tCO₂), but has not published updates since February 2025. 

• EU Emissions Trading Scheme (ETS) update: In July 2026, the European Commission proposed to expand the ETS to address emissions from flights departing the European Economic Area (EEA) to destinations within 5,000 km. To avoid double charging emissions also regulated under CORSIA, the Commission proposed to deduct CORSIA costs from airlines’ ETS obligations. While the Commission flagged concern about the stringency of CORSIA eligibility criteria, the proposed rules would not impact demand for Phase 1 EEUs. Still, it is worth watching for future restrictions on which credits EU airlines can use for CORSIA, whether in Phase 1 or 2. 

• Supply financing vehicles: The LEAF Coalition—which purchases credits verified under the CORSIA-eligible ART TREES standard—has signed over US$1.5 billion worth of purchase agreements with host countries. The Forest Carbon Partnership Facility (FCPF) and BioCarbon Fund Initiative for Sustainable Forest Landscapes (ISFL), both CORSIA-approved for Phase 1 in early 2026, have built jurisdictional REDD+ pipelines across dozens of countries. As projects mature, it will be worth watching how issued credits are marketed across compliance and voluntary channels.

Strategic Considerations

Avoided emissions credits dominate early CORSIA supply—and consequently demand—principally from avoided deforestation and clean cooking projects. As there is no regulatory premium for higher-cost CDR, this is not surprising. But as the market matures and supply diversifies, airlines are likely to begin differentiating on geography, co-benefits, and environmental performance. Corporate interest is growing in projects that abate non-CO₂ superpollutants, due to their outsized near-term climate impact. As many of these projects are based in countries actively issuing LoAs, this may soon translate into a supply of superpollutant EEUs. Some airlines are reluctant to procure aggressively now, anticipating the upcoming availability of higher-quality credits.

Credits that hold value across multiple frameworks could carry a strategic premium. A credit also eligible for Singapore's carbon tax, Switzerland's CO₂ Act, or SBTi claims may offer more durable demand than one tied to a single use case. While specific requirements vary significantly, we are beginning to see convergence around broad principles, such as the need for Article 6 authorization for credits used in compliance markets tied to NDCs. Procurement and project development strategies could begin to favour credits that confer wider market optionality. 

The precondition for all of this is policy stability. Longer-term offtake agreements, portfolio strategies, and meaningful investment in project development depend on confidence that CORSIA rules will hold. Efforts to soften emissions regulations in response to energy price shocks are now testing this confidence, from proposed changes to soften the EU ETS to Singapore's deferral of its SAF levy. Tracking price signals, enforcement developments, and authorization trends will be essential for identifying firm demand and where the opportunities lie.

Conclusion

Effective engagement with CORSIA requires more than developing quality projects. It means understanding methodological eligibility requirements, navigating Article 6.2 authorization processes, tracking a network of overlapping national regulations, and staying ahead of a rapidly evolving market landscape. Relae (formerly Carbon Direct) brings together policy, market, and scientific expertise to help clients on all of these fronts.

Frequently Asked Questions

Which carbon credits can airlines use for CORSIA compliance?

CORSIA Eligible Emissions Units (EEUs) must be issued by crediting standards approved by ICAO's Technical Advisory Body. Every approved standard currently has exclusions on certain methodologies and project types, so eligibility is granular rather than blanket. EEUs must also have a host country Letter of Authorization confirming a corresponding adjustment under Article 6.2 of the Paris Agreement.

Is CORSIA actually enforceable?

In all phases, CORSIA obligations are legally binding when a country writes them into domestic law. Countries participating in Phase 1 are expected to do this, but not all have, and enforcement remains uncertain in several key aviation markets (e.g., the United States). Even where enforcement exists, penalty regimes vary significantly in stringency and design. 

How does the July 2026 EU ETS proposal affect CORSIA?

The European Commission's proposal to expand ETS coverage to more flights does not reduce demand for CORSIA credits. While it would lead to overlap between flights covered under CORSIA and the ETS, as proposed, airlines could have CORSIA costs effectively deducted from their ETS allowance obligations. However, the Commission has signalled continued scrutiny of CORSIA's effectiveness, which could shape future limits on the credits EU airlines are allowed to use.

Key Takeaways

• Decarbonizing steel is key to meeting ambitious climate targets in the face of rapidly expanding AI infrastructure as well as broader infrastructure growth.
• The gap between corporate climate ambitions and near-term commercial reality is widening. Despite strong demand signals from hyperscalers and other major buyers, leading producers have recently canceled or delayed flagship green steel projects, citing high energy costs, slow hydrogen market development, and unfavorable policy environments. 
• Bridging this gap requires significant capital investment and supporting mechanisms to scale low-carbon technologies. Environmental attribute certificates offer an effective mechanism to channel capital toward transformative, low-carbon steel projects, supporting technology scale-up, as well as providing a way for buyers to meet their emissions reduction targets.  
• To protect the credibility of environmental attribute certificates as a market mechanism for decarbonization, projects should seek to meet rigorous quality criteria such as additionality, verifiability, and catalytic impact.

Forging New Climate Ambitions for Steel Production

Decarbonizing steel production is essential to meet global climate targets. Steel production accounts for approximately 7–9% of global CO₂ emissions. This is driven chiefly by coal-based primary steelmaking, which still accounts for the majority of global production. Globally, at least 1.8 billion tonnes of crude steel were produced in 2025 to serve a broad array of industries including real estate, infrastructure, automotive, and data center construction. 

As hyperscalers race to build the infrastructure underpinning the AI revolution, steel demand for data center construction, and associated energy infrastructure, is increasing. While the relative share of data center demand for steel versus global steel demand is small, the need for approximately 20,000 tonnes of steel per data center has a material impact on hyperscaler’s public climate commitments. Microsoft, Meta, and other large technology companies have set ambitious 2030 climate targets that include their scope 3 emissions. The embodied carbon of the steel used to build their data centers sits squarely in scope 3.

Hyperscaler’s climate commitments have generated sector-specific demand for decarbonized steel, presenting an opportunity to affect steel decarbonization more broadly. Despite this demand, the supply of low-carbon steel remains limited. The industry faces significant scale-up challenges due to the diffuse nature of demand and the nascent market. Catalyzing growth in decarbonized steel production will require market innovations and new production pathways designed to overcome these challenges. Credible environmental attribute certificates can help bridge the gap between today’s market and tomorrow’s low-carbon steel sector.

What is an Environmental Attribute Certificate?

An environmental attribute certificate (EAC) represents the environmental attributes of a product that can be unbundled and transacted separately from the underlying physical commodity. The most widely used EACs today are renewable energy certificates (RECs), which track the environmental attributes of renewable electricity. The same concept can also be applied to steel and iron, as well as to materials such as cement and concrete.

In a book and claim model, a steel producer can implement a verified emissions reduction intervention, quantify the resulting lowered carbon intensity per tonne of steel produced, and convert that into tradeable certificates. Buyers can then purchase those certificates to support the deployment of low-carbon steelmaking capacity in cases where direct procurement of low-carbon steel is currently impractical due to geographic, contracting, or scheduling incompatibilities.

EACs are distinct from carbon credits. They do not represent emissions reduced or avoided relative to a counterfactual; they represent the intrinsic carbon intensity of the material produced, measured through a life cycle assessment. 

Decarbonizing Steel Requires Significant Capital and Infrastructure Deployment

Steel Production Today

Steel is currently made via three main production routes. About 71% of the world’s steel is produced through the blast furnace–basic oxygen furnace (BF-BOF) route, which emits an average of 2.33 tonnes of carbon dioxide (tCO₂) per tonne of crude steel. A further 24% is produced using scrap-based electric arc furnaces (EAFs), which emit 0.68 tCO₂ per tonne on average—far lower, but still dependent on the carbon intensity of grid electricity. The remaining roughly 5% uses direct reduced iron combined with an EAF (DRI-EAF), typically using natural gas, emitting 1.37 tCO₂ per tonne on average.

While increasing scrap-based production is a critical decarbonization lever, scrap availability is limited. Primary steel production, which uses iron ore as the main feedstock rather than recycled scrap, will remain necessary at large volumes through 2050. This makes it essential to decarbonize ore-based pathways, especially ironmaking: the step where iron ore is reduced to iron and where most emissions occur.

Decarbonizing ore-based steel production requires one of three fundamental interventions: (1) replacing coal and natural gas with low-carbon fuels such as hydrogen or bio-coke, (2) electrifying ironmaking directly, or (3) capturing and storing the CO₂ generated from fossil-fuel-based processes. All three involve significant capital expenditure and dependencies on infrastructure that is not yet in place at the necessary scale. As a result, the energy and cost challenge is substantial.

Low-Carbon Steel: Emerging Pathways

A range of transformative technological pathways are currently in development to overcome these barriers, offering the potential to deliver deep decarbonization to the steel industry exceeding 90% by 2050: 

• Hydrogen-based DRI-EAF: Using green hydrogen instead of natural gas within the DRI process provides a pathway to significantly lower the carbon intensity of ironmaking. Producers such as Stegra are deploying commercial-scale facilities designed to utilize 100% green hydrogen to reduce iron ore.
• Electrifying ironmaking: 
  
  • Molten oxide electrolysis: Boston Metal is commercializing a process that uses electricity to directly convert iron ore to molten metal through electrolysis at high temperature, eliminating the need for hydrogen or carbon reductants entirely.
  • Low-temperature electrowinning: Colorado-based startup Electra uses renewable electricity to extract iron from ore via an aqueous electrochemical process that operates at near-ambient temperature. 
• Carbon capture and storage (CCS): For blast furnaces and DRI plants with long remaining lifetimes, retrofitting with CCS technology can significantly reduce emissions. With new high-emitting capacity still being built, and assets expected to operate for decades, integrating CCS will be essential to avoid long-term carbon lock-in and to decarbonize these facilities over time. To date, commercial-scale deployment remains limited. The Al Reyadah facility at Emirates Steel is the only project currently capturing CO₂ from a DRI process at scale, though a handful of other large-scale projects have entered the development pipeline.

Progress and Setbacks: A Mixed Picture

The past year sent contradictory signals about the pace of steel decarbonization. On the demand side, technology companies with ambitious climate targets are actively signaling their intent to procure near-zero steel and support its development.

In September 2025, Microsoft and Stegra announced a landmark agreement that combines a physical supply deal for low-carbon steel with a separate EAC purchase agreement. Around the same time, Meta announced an agreement with Electra to purchase EACs tied to the startup’s clean iron production, becoming one of the first buyers to use the EAC model for an entirely novel, pre-commercial ironmaking technology. Nucor, the largest US steelmaker, also entered into a physical iron purchase agreement with Electra.

Despite these demand signals, the industry has experienced significant setbacks. A series of low-carbon steel project cancellations and delays has raised questions about the pace and viability of the steel transition, especially due to the high costs associated with green hydrogen production.

At present, the green premium for most low-carbon steel remains too high for buyers. A combination of sustained policy support, long-term demand signals from buyers willing to pay more, and scaling of supporting industries, such as green hydrogen production, is necessary for the low-carbon steel industry to be successful in the long run.

How EACs Can Bridge the Funding Gap in Steel

EACs unbundle low-carbon steel attributes from the physical material, reducing the friction between buyers who are willing to pay a green premium and geographic or logistical constraints that may inhibit physical offtake. Buyers, such as hyperscalers procuring conventional steel for data center construction in locations where low-carbon steel is not yet available, can purchase these certificates to support the development of low-carbon capacity, attribute lower-carbon production to their steel use via a market-based mechanism, and advance toward their scope 3 targets.

A primary objective of the Criteria for High-Quality Environmental Attribute Certificates in the Concrete and Steel Sectors, jointly developed by Relae (formerly Carbon Direct) and Microsoft, is to establish high-integrity standards for the EAC market in these sectors. For steel EACs, that means demonstrating significant emissions reduction performance by reaching at least Progress Level 2 in the ResponsibleSteel Decarbonization Progress Levels framework, and aiming to achieve Progress Level 3 by 2030. ResponsibleSteel’s scrap-variable benchmark provides a technology-neutral mechanism to evaluate emissions reduction performance by accounting for the specific proportion of scrap used.

EACs for steel are designed to be catalytic. Rather than supporting incremental improvements that are already becoming cost-competitive, they should target transformative capital changes, such as replacing BF-BOF routes with DRI-EAF, adopting low-carbon hydrogen in DRI processes, or deploying novel ironmaking technologies. Multi-year purchase agreements are particularly powerful because they provide the investment certainty that first-of-a-kind projects need to access capital at a lower cost.

What this Means for Buyers and Suppliers of Low-Carbon Steel 

Whether you are producing or procuring steel, EACs are only one part of a broader decarbonization strategy. For buyers with significant emissions from steel, and other building materials such as cement and concrete, EACs can be a powerful tool to help advance scope 3 reduction goals where supply for physical low-carbon materials is limited. Suppliers can complement commercialization strategies for low-carbon materials by using EACs to monetize emissions reductions, generate additional revenue to support decarbonization investments, and help scale markets for low-carbon materials. Navigating the steel market requires decisions at the intersection of technical feasibility, greenhouse gas accounting, and capital strategy. Key considerations include:

• Greenhouse gas accounting and reportability: Cradle-to-gate emissions for steel production must be tracked using life cycle assessments and should strive for interoperability with environmental product declarations (EPDs). EAC transactions must be reported transparently, especially given the absence of formal market standards at this stage.
• Additionality and catalytic impact: EAC purchases must demonstrably support projects that would not proceed without financial support from the EAC market mechanism, and projects should have a credible pathway toward the near-zero (Progress Level 4) threshold on the ResponsibleSteel framework.
• Avoiding double counting: EAC buyers must verify that the environmental attributes they purchase are not also being claimed by the physical product buyer via an EPD.

FAQs

What is an environmental attribute certificate (EAC) for steel?
An EAC represents the environmental attributes of low-carbon steel, unbundled from the physical material itself, so a producer can quantify a verified reduction in carbon intensity per tonne and sell that value as a separate, tradeable certificate. Buyers can purchase EACs to support low-carbon steel production while still working toward their own emissions targets.

How is an EAC different from a carbon credit?
An EAC reflects the intrinsic carbon intensity of the material itself, measured through a life cycle assessment. That's different from a carbon credit, which represents carbon dioxide actively avoided, reduced or removed from the atmosphere relative to a baseline.

How are AI data centers impacting the demand for low-carbon steel?

Data centers use roughly 20,000 tonnes of steel each, and as hyperscalers build out AI infrastructure, that steel use counts toward their scope 3 emissions and public climate targets. That's turned data center construction into a meaningful driver of demand for low-carbon steel, even though supply remains limited.

What makes an EAC credible enough to count toward a company's emissions goals?
A credible steel EAC needs to meet criteria like additionality (the project wouldn't happen without the EAC revenue), verifiability through life cycle assessment, and catalytic impact toward transformative technology rather than incremental gains. Relae (formerly Carbon Direct) and Microsoft jointly developed criteria for high-quality EACs in the steel and concrete sectors, which set a threshold of at least Progress Level 2 on the ResponsibleSteel Decarbonization framework today, rising to Progress Level 3 by 2030.

Can a producer sell an EAC and also get credit for the physical steel elsewhere?
No. EAC producers need to confirm the environmental attributes they're selling aren't also being claimed by whoever buys the physical steel through an environmental product declaration; otherwise the same emissions reduction gets counted twice.

Key Takeaways

• The Greenhouse Gas (GHG) Protocol’s proposed scope 2 revisions would shift many large power buyers from annual renewable energy certificate (REC) accounting to 24/7 hourly matching and reveal a larger emissions gap than most inventories currently report.
• Of all the US grid regions modeled, the emissions gap between annual and 24/7 hourly matching is widest in PJM Interconnection (PJM) and the Electric Reliability Council of Texas (ERCOT), the markets where data center load is growing fastest.
• Relae's modeling quantifies the shift from annual to 24/7 hourly matching: serving a 4-gigawatt (GW) data center load at 100% hourly carbon-free energy requires 9.6 GW of additional clean capacity in ERCOT and 10.5 GW in PJM, a roughly 800-megawatt premium in PJM that translates directly into cost and siting strategy.
• Closing that gap requires investments in clean, firm generation technologies, like natural gas with carbon capture and storage (CCS), battery storage, and geothermal. The optimal mix varies by market and load profile, which means modeling current and future emissions positions under 24/7 accounting to understand the best procurement options for a specific portfolio.

Annual REC Accounting No Longer Holds at Data Center Scale

For years, large corporate energy buyers have relied on a straightforward approach: purchase renewable energy certificates (RECs) or sign virtual power purchase agreements (VPPAs) to offset market-based scope 2 emissions. Under the current GHG Protocol guidance, these instruments allow companies to claim low or zero emissions regardless of when or where clean energy is actually generated. When corporate clean energy demand was modest, this fueled new renewable project development while aggregate grid emissions were trending down.

That approach worked, until now. Energy demand from data centers and hyperscalers is surging. The Federal Energy Regulatory Commission (FERC) reported more than 50 GW of data center capacity operating in the US at the end of 2025, much of it concentrated in regions where local clean generation cannot keep pace. When corporate clean energy demand was modest, the gap between contractual claims and physical generation was small enough that few questioned this argument. At hyperscaler levels, with load concentrated in a handful of grids, that gap is becoming too large to ignore.

From a climate perspective, well-designed renewable procurement has created real impact by channeling corporate capital into new clean generation, and reducing CO2 emissions anywhere to benefit the climate everywhere. From a grid perspective, power consumption and generation must balance in real time, and the flow of electricity is constrained by the physics of the transmission system. Some regulators, investors, and standard-setters argue that corporate clean energy claims should be grounded in this second, engineering perspective rather than the first. The GHG Protocol's proposed revisions reflect that view, and would force buyers to defend their claims against it.

Relae’s modeling of this 24/7 framework in PJM and ERCOT helps quantify its costs and emissions implications in the markets where the stakes are highest.  

What Does 24/7 Hourly Matching Mean for Scope 2 Accounting?

The biggest proposed change to the GHG Protocol’s current Scope 2 Guidance is the move from annual power reporting and matching to a 24/7 approach. Instead of calculating emissions with an annual emissions factor (EF) based on their independent system operator (ISO) or eGRID region for each megawatt-hour (MWh) consumed, companies would need to use hourly-specific EFs. 

Companies would still be able to retire RECs to reduce their market-based emissions. However, companies would need to show that these RECs came from clean energy that was generated on the same grid, in the same hour as their facilities consumed power. This makes annual, location-agnostic REC retirement, currently the dominant practice, insufficient for 24/7 market-based accounting. 

Both the time restriction (hourly matching) and the location restriction (generation on the same grid as consumption) will make it more difficult for companies to retire RECs. For example, because today's methodology is location-agnostic, a New York-based company can retire RECs from a Texas wind farm (purchased unbundled or via a VPPA) to reduce its reported market-based scope 2 value. This has allowed renewable development to follow the best resource sites rather than the load. Similarly, the time of day that the wind farm generates energy is irrelevant, as long as it is approximately in the same calendar year. 

Under the proposed revisions, retiring these RECs would no longer be acceptable for the New York company, since they would fail both location- and hourly-matching requirements. As a result, companies with large REC portfolios today may no longer be able to retire them in order to reduce their market-based scope 2 emissions, if the proposed revisions take effect. These companies may face significant unmatched consumption under 24/7 accounting, especially during evening peaks or grid stress events when fossil-based generation fills the gap. 

Annual Matching vs 24/7 Hourly Matching

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The figure below illustrates the gap between what a representative large buyer reports under the current annual location- and market-based methodologies, versus what an hourly 24/7 analysis reveals.

Understanding this emissions gap is the essential first step for buyers to make informed decisions about which instruments to retain, which contracts to renegotiate, and where new investment will matter most. If the proposed scope 2 revisions are enacted, companies procuring clean energy will be disincentivized from buying RECs sourced from variable renewables in distant locations, and instead will find it more favorable to invest in same-grid clean, firm generation, such as geothermal, nuclear, and renewables plus storage. RECs from these projects would qualify to be retired against market-based scope 2 emissions under the proposed revisions, where today's distant-wind or off-peak-solar RECs would not.

Where Pressure Is the Highest: ERCOT and PJM

Two markets stand out for projected hyperscaler load growth: PJM, which covers the extended mid-Atlantic region, and ERCOT in Texas. Both are on track to absorb massive increases in data center demand over the next decade, and both expose the limits of annual REC accounting in ways that will be hard to ignore under the new proposed framework.

PJM: 60% Fossil Generation Means High Marginal Emissions

PJM is one of the largest and most complex wholesale electricity markets in the world. Its generation mix still includes 60% coal and natural gas, which means hourly emissions intensity remains high, particularly during evening peaks and grid stress events when fossil generation dominates the dispatch stack. 

Buyers relying solely on annual REC retirement may show low market-based scope 2 emissions today, but a 24/7 analysis tells a different story. For PJM-based buyers, this means hourly matching gaps will be largest during evening and overnight hours, when nuclear and storage become disproportionately valuable relative to additional solar.

ERCOT: Solar and Wind Don’t Peak When Demand Does

Texas has abundant wind and solar, with solar generation growing nearly 7x since 2020, but those resources don’t always run when demand peaks. While fossil-based generation has declined since 2020, it still comprises more than half of ERCOT’s generation. Solar dominates midday, wind peaks in the evening, and natural gas fills the gaps, especially during high-demand evenings or extreme weather events. 

Buyers with large ERCOT footprints may find that VPPA portfolios, which generate most of their clean energy in off-peak hours, already satisfy the proposed location-based test but fail on hourly matching. Battery storage and demand flexibility could help bridge the gap.

Figure 3 below quantifies that gap in both markets by showcasing the carbon-free energy (CFE) score in ERCOT and PJM, as well as the additional capacity required for a 4 GW load to achieve a 100% CFE target. The CFE score is the share of grid-supplied electricity in a given hour that comes from carbon-free sources, and is the metric the proposed scope 2 revisions would use to evaluate hourly matching. A 100% CFE target means electricity consumption is matched to carbon-free generation in every hour of the year.

In the left panel, a representation¹ of each market's 2030 hours are sorted by grid (CFE) score, from the dirtiest hour on the left to the cleanest on the right. Neither grid approaches 100% carbon-free on its own, and the shaded areas represent the unmatched hours a buyer claiming 100% clean energy through annual instruments would actually carry under 24/7 accounting. The gap is the maximum unmatched hours a buyer might be exposed to, as some RECs procured through annual matching may qualify under the new rules, if satisfying the locational and hourly requirements.

The right panel translates that gap into action. The additional co-located clean generation and storage required to serve a representative 4 GW load (roughly 5% of the forecast 2030 C&I load in ERCOT and 4% in PJM) at a 100% hourly CFE target, on top of what the underlying grid already provides.

A few patterns are worth highlighting. First, the left panel confirms that PJM’s grid will still spend materially more hours below 100% carbon-free than ERCOT’s in 2030, a direct consequence of the coal- and gas-heavy generation mix described above. Notably, ERCOT's curve reaches 100% in a meaningful share of hours (windows when the grid is running entirely on carbon-free resources), while PJM's never does, meaning some fossil generation is dispatched in every hour.  

Second, the ISO a buyer operates in drives a meaningful difference in build-out: hitting 100% hourly CFE for a 4 GW load takes 9.6 GW of additional capacity in ERCOT and closer to 10.5 GW in PJM. This indicates the advantage of achieving hourly and locational matching in already clean grids, which may influence a buyer choosing where to site new workloads. 

Renewables have the largest share of the additional capacity in both markets (5-6 GW), paired with significant long-duration energy storage (~2 GW), while natural gas with CCS provides meaningful clean, firm capacity (~3 GW). ERCOT’s storage share of capacity is slightly larger, reflecting the midday-solar/evening-load mismatch, while PJM leans a bit more on natural gas with CCS, where clean, firm generation does more of the heavy lifting due to lower wind speeds and solar irradiance than Texas.

The right panel also illustrates why clean, firm technologies (natural gas with CCS, advanced nuclear, and enhanced geothermal) are likely to be included alongside renewables and batteries in any serious 24/7 portfolio. With only renewables and batteries, hitting the same target requires about double the total generation and storage capacity. In both markets, targets that look achievable today on an annual REC basis will require materially more capital and a different mix of resources, under 24/7 accounting. 

Top Questions Large Power Buyers Need to Model Before the Rules Change

The GHG Protocol revisions are not finalized, and the timing of any mandate remains uncertain, which is exactly why modeling cannot wait.

A useful self-test for any large power buyer is: can your team answer the following today with defensible numbers?

• What is your hourly CFE score across your largest load centers, and how far does it sit from your reported market-based emissions?
• Which of your existing VPPAs and REC contracts hold value under 24/7 accounting, and which become effectively stranded?
• What mix of resources delivers the incremental clean, firm capacity that closes your gap in PJM, ERCOT, or wherever your load is concentrated at the lowest cost?
• If your next gigawatt of load were sited in a different ISO, how would your emissions position change?

Clean firm projects do not appear off the shelf. Advanced nuclear, enhanced geothermal, and natural gas with CCS all carry multi-year development timelines, and corporate offtake agreements are often what get these projects financed in the first place. Buyers who engage now help shape the project pipeline that will be available in their target markets in 2030, and can lock in offtake terms before competition for the most valuable sites tightens. Buyers who wait until the methodology is final will be working with shorter lead times, fewer development partners, and less leverage to specify projects that fit their load profiles and hourly matching needs.

Frequently Asked Questions

What is 24/7 hourly matching, and how does it differ from today's REC accounting?

Today's scope 2 accounting lets companies retire renewable energy certificates (RECs) from any grid, at any time of year, to offset their emissions. The GHG Protocol's proposed 24/7 hourly matching would require RECs to come from clean generation on the same grid, in the same hour a facility consumes power, making most of today's location-agnostic RECs ineligible for market-based accounting.

Why are PJM and ERCOT under the most pressure from this shift?

Both markets are absorbing the fastest-growing data center load in the country, and both still lean on fossil generation to meet demand outside peak renewable hours. PJM's generation mix is 60% coal and gas, while ERCOT's solar and wind often don't peak when demand does, so buyers in these markets face the largest gaps between their annual REC claims and their actual hourly carbon-free energy score.

How much additional clean capacity does it take to close the gap?

Relae's modeling finds that serving a 4 GW data center load at 100% hourly carbon-free energy requires 9.6 GW of additional clean capacity in ERCOT and 10.5 GW in PJM. That capacity mix leans on renewables and long-duration storage in both markets, with natural gas with CCS playing a larger role in PJM, where wind and solar resources are weaker.

What should power buyers do before the GHG Protocol revisions are finalized?

Start modeling now. Buyers should know their hourly carbon-free energy score, understand which existing VPPAs and REC contracts hold value under 24/7 accounting, and identify the lowest-cost mix of clean, firm resources that closes their gap. Clean firm projects like advanced nuclear, enhanced geothermal, and natural gas with CCS take years to develop, so buyers who engage early have more influence over the project pipeline and better offtake terms.

Modeling the 24/7 Emissions Gap with Relae

For large power buyers assessing what the proposed GHG Protocol revisions mean for their power procurement portfolio, Relae's Advanced Power Emissions Analysis solution models the gap between current market-based reporting and what 24/7 accounting would reveal—by market, load profile, and technology stack.