Summary

• Most companies with scope 2 exposure are already buying RECs. The harder question is whether those RECs are the right ones for your organization. Do they match the right market? Are they from recently commissioned assets, retired within the right time window, and backed by a sourcing process that holds up under disclosure scrutiny?
• The same instrument goes by different names. RECs in the US, Guarantees of Origin (GOs) in continental Europe, REGOs in the UK, and I-RECs across APAC, Latin America, and Africa. The book-and-claim mechanism is the same across geographies, but the market rules, registry infrastructure, and supply availability are not.
• Geography is the most common compliance failure point. Today RE100 treats the entire US as one market, and the GHG Protocol lets you draw a broad boundary. But this is changing. Under SBTi CNZS V2.0, RECs must come from the same deliverability region as consumption — so a Texas REC can't cover a Massachusetts facility, and within the Eastern grid, real transmission constraints mean cross-ISO matching (like Illinois to Massachusetts) will likely be disallowed once final guidance is published.
• Asset age is the second failure point. RE100 now requires at least 85% of certificates from generators commissioned within the last 15 years. Commodity RECs from legacy hydro don't clear this bar. And Green-e's 21-month vintage window, recognized by RE100 and accepted for CDP disclosure, means yesterday's registry surplus is today's eligibility problem.
• The GHG Protocol's scope 2 rules are being revised (expected to finalize in 2027). The new guideline is moving toward tighter geographic and temporal matching. The direction of travel is hourly matching and stricter geography. Annual RECs from the right market are the compliance floor today, not the ceiling for much longer.

Many companies have already purchased RECs. Not all are able to demonstrate that the certificates in their portfolio match the right market, reporting period, commissioning-date requirement, registry standard, and disclosure framework.

What is a Renewable Energy Certificate?

A Renewable Energy Certificate (REC) is a market-based instrument representing the environmental attribute of 1 MWh of electricity generated from a renewable source, such as solar, wind, or hydro, and fed into the electrical grid. Purchasing and retiring a REC lets you claim that your electricity is renewable for sustainability reporting purposes, independent of the source of electrons that physically reach your facility.

The underlying mechanism is book-and-claim. When a renewable energy generator produces electricity, it receives one certificate per MWh. That certificate can be sold to companies separately from the electricity itself. When a buyer company retires the certificate, it creates an exclusive, non-transferable claim: only the certificate retiring party can count that electricity as renewable in their sustainability report.

Regional variants do the same thing under different names. RECs are the US term. I-RECs (International Renewable Energy Certificates) are used in APAC, parts of Latin America, and Africa. Guarantees of Origin (GOs) are the European equivalent, governed by the Association of Issuing Bodies (AIB). In the UK specifically, the instrument is a Renewable Energy Guarantee of Origin (REGO). All operate on book-and-claim. For buyers, the operative question is geographic: the right instrument is determined by where your facilities operate, and each market has its own supply constraints and quality considerations.

The geography rule, and why it's more complex than it looks

RECs must come from the same market or grid as the electricity your facilities consume. Under RE100 this means staying within the US market. Under SBTi's CNZS V2.0 it's stricter: RECs need to match your deliverability region. Under CNZS V2.0 (effective February 2027), this will be the requirement most commodity REC purchases struggle to meet.

The reason goes back to what scope 2 accounting is trying to do. Scope 2 emissions are the carbon emissions released by the power plants generating the electricity your facilities use. The carbon intensity of that electricity is determined by your local grid mix. A company operating in a coal-heavy grid carries a high scope 2 footprint. Buying a cheap certificate across the country, one with a lower-carbon grid, papers over the regional difference in renewable energy adoption. The same-market rule strengthens a credible REC by directing capital toward renewable generation in the grid your facilities actually depend on and support building the capacity that will eventually decarbonize it.

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The GHG Protocol Scope 2 Guidance distinguishes between location-based accounting that uses average grid emissions factors for wherever your facilities are located, and market-based accounting that substitutes those factors with the attributes of the specific electricity products you've purchased, including RECs. Companies must report both, and RE100 and SBTi targets allow the use of market-based accounting for achieving corporate targets and demonstrate progress through procurement decisions.

The complexity compounds with each country in which a company operates. In the United States alone, three synchronous interconnections — Western, ERCOT, and Eastern — define the outer market boundaries, with the Eastern further divided into five ISO/RTO markets (including PJM, MISO, SPP, ISO-NE, and NYISO). For companies validating targets under SBTi's CNZS V2.0 standard, the new deliverability requirement becomes important: RECs must come from generation that can plausibly serve your load, within a defined deliverability region. The three US synchronous interconnections define the outer eligibility boundary. A California REC cannot cover Texas load; a Texas REC cannot cover Illinois load. The GHG Protocol's ongoing Scope 2 revision is moving in the same direction, but has not yet finalized equivalent rules. In Europe, Guarantees of Origin can be transferred across participating EU and EEA markets through the AIB system, including between countries on different synchronous grids. Not all transfers may be eligible for any given load under SBTi rules: CNZS V2.0 requires certificates to match the deliverability region serving the load, unless the buyer can demonstrate qualifying physical transmission rights or contractual arrangements. Expect SBTi to eventually follow guidance from the GHG Protocol; thus, forthcoming guidance should provide greater clarity on how those deliverability regions are defined and what transfers are eligible for demonstrating target progress.

In APAC, each country is its own market, where Vietnamese I-RECs cannot cover Taiwanese operation. China’s recent alignment with RE100 closed a major gap, though formal GHG Protocol recognition is still pending. Where no certificates are accessible, only location-based accounting is the only option for the company. Consequently, a "global renewable energy program" is always several regional programs running in parallel, each with its own registry, price and rulebook.

Three questions to evaluate any REC purchase

A REC from a 20-year-old hydro dam in a market with no renewable deficit is a very different thing from a REC from a newly built solar project in a coal-heavy grid. Both can satisfy the GHG Protocol's market-based method, but only the latter is likely to meet RE100 and CNZS V2.0's commissioning requirements.

Three questions clarify the differences, and experienced buyers should be asking all of them before any purchase.

1. Is this the right market?

RECs must come from the same market as the electricity consumption they map to. Most buyers know the rule in principle, but the harder question is whether compliant supply actually exists in the markets where you operate, and which instrument applies. Japan accepts both NFCs and I-RECs but they require different procurement infrastructure. Australia has LGCs and nothing else. China’s GEC system is now RE100-aligned following reforms in 2025, closing a major prior gap. The geography check becomes the first test of whether your program is buildable in a given market. If the answer is no, only location-based accounting remains.

2. Is it eligible under your framework?

The answer depends on which standard governs your reporting, and GHG Protocol, RE100, SBTi's CNZS V2.0, or CDP are not interchangeable. None of them require an additionality test for RECs today, and their quality bars differ. RE100 requires that at least 85% of certificates come from generators commissioned within the last 15 years and are retired within the applicable vintage window. The commissioning rule screens out legacy hydro and long-running assets that would operate regardless of certificate demand; the vintage constraint, 21 months under Green-e in the US, 12 months in most international markets, is a meaningful contrast with carbon credits where older vintages are routinely retired. Buyers from a carbon background often don't expect RECs to be time-bounded. CNZS v2 applies the same 15-year commissioning limit with a 12-month vintage default, allowing established market windows as exceptions. The GHG Protocol, as of now, is more permissive on both asset age and vintage window..

A caveat for CNZS V2.0 net-zero commitments: Under CNZS v2, RECs count toward near-term targets but not the net-zero year. At that point, SBTi requires actual decarbonization of electricity consumption, not just annual attribute certificates.

3. What's the renewable energy story in that grid?

A REC from a grid already above 90% renewable is technically valid but carries a weaker impact signal than one from a fossil-heavy grid where new clean capacity is being built. Most frameworks don't formally disqualify the first, but CNZS V2.0's requirement that market instruments "decarbonize the relevant system" is beginning to close that gap for SBTi-committed buyers.

Price is the most visible, if imperfect, proxy for all three signals combined. In the US, commodity unbundled RECs in oversupplied voluntary markets can sell for a few dollars per MWh or less, while project-specific, certified RECs (e.g., Green-e) from newer wind and solar projects often carries a meaningful premium. The same dynamic plays out more sharply in APAC. Vietnam is a high-volume, oversupplied I-REC market, with prices trading around US$0.35 per MWh. Singapore solar I-RECs are trading around US$20 per MWh in 2026 due to high corporate demand and limited local supply. The spread reflects different grids, different scarcity, and very different demand signals from discerning corporate buyers.

Why building a global REC program is hard

For companies with operations in a single market, REC procurement is relatively straightforward. For multinationals, complexity grows quickly. A company with facilities across the US, UK, Germany, Singapore, and Japan is managing five REC programs, each with its own registry infrastructure, pricing dynamics, and eligibility rules.

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APAC is peak complexity. I-RECs operate across a fragmented landscape of country-specific registries, each with different liquidity, infrastructure maturity, and alignment with international frameworks. Japan has its own NFC system alongside I-RECs, and which certificates qualify under RE100 and SBTi market-based accounting for Japanese operations is a question buyers regularly get wrong. Australia's LGCs operate under a separate regime that doesn't map directly to I-REC infrastructure.

The challenge isn't just sourcing RECs in multiple markets. It's building one coherent program across them: aligning procurement calendars, retirement deadlines, and vintage windows that don't map neatly across regions; knowing which instruments satisfy which frameworks in each jurisdiction; and managing supply constraints in markets where compliant certificates are limited or unavailable. A company at 95% renewable achievement often find the last few percentage points the hardest to source, and the successful program rests on local knowledge and careful diligence in each geography.

When to move beyond spot RECs to VPPAs or aggregated structures

RECs work well for companies with distributed electricity footprints across multiple markets. When consumption is large and concentrated, as in a data center or manufacturing facility, a VPPA (Virtual Power Purchase Agreement) or physical PPA often makes more sense. Two factors motivate the shift, and either is sufficient on its own: price and additionality.

Mechanically, a VPPA is a long-term contract with a renewable energy generation facility. You receive the RECs generated by the project and a financial settlement based on the difference between your contracted strike price and the wholesale electricity price where the facility is located.

The price certainty and predicability logic is one that every procurement team understands: spot buying offers flexibility but price exposure; a long-term supply agreement with a generator locks in a contracted strike price over a multi-year term, hedging against market swings in both REC prices and rising electricity costs simultaneously. In North American markets, companies that signed VPPAs during the low-price window of 2018-2021, before supply chain disruptions and rising interest rates, are often procuring well below today's prices.

The additionality case is more fundamental. Most spot RECs are not additional, in the sense that they are certificates from generation that already exists, and buying them builds no new generation capacity. A VPPA does something different: your multi-year commitment can enable a developer to secure project financing. Without a creditworthy corporate offtaker, many projects don't move forward. This is the distinction that matters once the bar moves past a simple geography and asset-age test. CDP scores additionality higher, and investors and NGOs are increasingly asking whether your renewable energy procurement is funding the energy transition. Frameworks are signaling the same direction: CNZS V2.0's requirement that market instruments "decarbonize the relevant system" is a meaningful shift in language, even if it doesn't yet formally require additionality for RECs. Companies that want their renewable energy claims to hold up over time should follow the additionality framework.

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For buyers below typical standalone VPPA thresholds, often 50,000 MWh or more per year, demand aggregation makes the structure accessible. A consortium of buyers can collectively contract with a single developer, sharing the economics and contractual paperwork, so that no single party carrying the full load.

In APAC, the VPPA market development is uneven. Australia is among the more developed markets in the region. Japan is developing, partly driven by GX-ETS compliance pressure. Southeast Asian markets are earlier. For companies with significant facility footprints in the region, modeling VPPA economics now, rather than when compliance pressure forces a rushed decision, is almost always worth the time.

The practical sequencing for most companies is starting with spot RECs to establish coverage across your scope 2 footprint, then layering in a VPPA or aggregated structure where consumption in a given market is large enough to justify the contract and where the additionality framework matters.

How RECs fit into a broader environmental program

As part of a resilient program, each certificate has its own role to play. RECs address scope 2, SAF certificates cover scope 3.6 air travel, carbon credits address other ongoing and residual emissions. These are not interchangeable instruments, and they are not sequential purchases. The companies running the most credible programs manage them as a coordinated portfolio from the start.

The maturation arc is similar to carbon credit procurement behavior: companies start with spot purchases, build familiarity with quality differentials, then move toward multi-year programs with structured sourcing, competitive tendering, and clear certification requirements. The wave of progression is now coming to RECs. Companies that matured their carbon programs first are well-positioned to apply the same discipline to scope 2 procurement, lest they mistake the commodity end of the REC market for a credible program.

That gap is where most programs run into trouble. Scope 2 market-based accounting requires RECs, but it doesn't require good RECs. The frameworks only establish minimum bars. The gap between minimum and credible is where disclosure scrutiny tends to land and where companies find out whether their program was built for the climate impact it claims.

The market’s direction is clear, with the GHG Protocol's 2027 revision expected to tighten both geographic and temporal matching requirements, in line with where RE100 has already moved with its 15-year commissioning rule and tighter vintage guidance. Advanced buyers are already asking about hourly matching as the next standard. Programs built to today's minimum may need significant restructuring in two to three years.

The reporting treatment for a well-built program is straightforward. RECs retired in your name, from a certified registry, from the same market as your electricity consumption, within the reporting year, appear under scope 2 market-based in your GHG inventory. The key requirements, geography, vintage, retirement, and certification, are all verifiable at the point of purchase.

Frequently asked questions

How do RECs show up in corporate sustainability reporting?

Purchased and retired RECs appear under scope 2 market-based in your GHG inventory, typically across CDP, GRI, and annual sustainability reports. The key requirements: the REC must come from a certified registry, be retired in your name, originate from the same market as your electricity consumption, and fall within the applicable vintage window. Your sustainability team or environmental consultant can confirm the exact treatment for your specific disclosure framework.

What is a REC vs. an I-REC?

A REC is the US term for a certificate representing 1 MWh of renewable electricity. An I-REC is the equivalent instrument used in international markets, including most of APAC, parts of Latin America, and Africa. In Europe, the equivalent is a Guarantee of Origin (GO); in the UK, a Renewable Energy Guarantee of Origin (REGO). All operate on the same book-and-claim principle. For buyers, the operative question is geographic: the right instrument is determined by where your facilities operate, and each market has its own supply constraints.

How does Patch approach REC sourcing?

Patch runs a competitive sourcing process across multiple suppliers and registries in each market, benchmarking quotes against current market pricing and screening certificates for alignment with buyer requirements, RE100 guidance, and CDP disclosure expectations. That review includes key attributes such as generation vintage, project commissioning date, eligible technology, market boundary, and registry certification standards. The process is documented and auditable, which matters when renewable electricity claims are subject to external review. For buyers building programs across multiple geographies simultaneously, the value of a managed sourcing process is consistency: the same quality standards and registry verification applied across every market in your footprint, rather than a patchwork of spot purchases assembled market by market.

If you're evaluating a REC procurement partner, the questions worth asking are: Can they show you the competitive bids? Can they confirm commissioning dates and vintage windows for every certificate before retirement? Do they have existing supplier relationships in the specific markets where your facilities operate, or are they sourcing cold?

What do RE100 and SBTi actually require for scope 2?

RE100 requires members to source 100% of their electricity from renewables annually using market-based instruments that meet its quality criteria: same-market geography, a vintage window of approximately 21 months around the reporting year, retirement in the applicable registry, and at least 85% of certificates from generators commissioned within the last 15 years. SBTi's CNZS V2.0 applies parallel requirements: the same 15-year commissioning limit, a 12-month temporal alignment default (with established market vintage windows allowed as exceptions), and deliverability regions defined by synchronous grid boundaries, transmission congestion, and regional connectivity. The two frameworks largely align, but CNZS v2 is marginally stricter on temporal alignment and does not carry the explicit 85% exemption structure.

Why do REC prices vary so much?

REC prices range from under $1 per MWh for commodity unbundled RECs in oversupplied markets to $100 or more in markets with deep supply scarcity. Price reflects additionality, vintage, technology type, certification standard, and local supply and demand. In 2026, Vietnam solar I-RECs are trading around $0.35/MWh; Singapore solar I-RECs are around $20/MWh. Both say "1 MWh of renewable electricity." They don't say the same thing about the grid they came from, the impact of your purchase, or whether the claim will live up to scrutiny.