Who Owns the Green Attribute: I-RECs, Carbon Credits, and the Carbon Tax in Colombian Solar

Executive summary

On April 23, 2026, Verra published VMR0017, its rewrite of the methodology used to credit grid-connected renewable power. It lets terrestrial solar plants register for carbon credits in any country the World Bank classifies as low, lower-middle, or upper-middle income. Colombia is upper-middle income. Since VCS version 4 took effect in 2019, Verra had limited new grid-connected renewable registrations to least developed countries, so this is the first opening in about seven years for a new Colombian solar plant. On April 30, the Integrity Council for the Voluntary Carbon Market (ICVCM) approved VMR0017 under its Core Carbon Principles, with a condition on additionality.

Two other markets already pay for the environmental side of a Colombian megawatt-hour. Companies redeem I-RECs to report the electricity they buy as renewable; Argus, citing registry data, put Colombian redemptions at about 4 TWh in February 2025 alone, up roughly 85% on a year earlier. Fuel buyers can avoid part of the national carbon tax by retiring domestic carbon credits.

Below I go through what each instrument is, what the public numbers say it is worth per megawatt-hour, who owns it under the contracts a solar plant signs, and what to ask a sponsor whose model includes any of it.

One megawatt-hour, three claims

An I-REC certifies that one megawatt-hour of renewable electricity was generated. In Colombia it is issued by Fundación ECSIM, the local issuer accredited under the I-TRACK standard. XM, the market operator, leads a separate domestic program, EcoGox, that certifies and registers renewable energy certificates. The buyer is usually a company reporting its Scope 2 emissions.

A carbon credit certifies one tonne of CO2 equivalent avoided. For a solar plant, the grid emission factor converts megawatt-hours into tonnes. UPME Resolution 085 of February 23, 2026 set the 2024 factor at 0.660 tonnes per MWh for wind and solar projects using Clean Development Mechanism methods, and at 0.220 for greenhouse gas inventories. The resolution says use of these factors is optional; a project may calculate its own under UNFCCC procedures.

The two factors answer different questions. The 0.660 figure is a combined margin, weighted toward the thermal plants that run at the edge of the system, and it estimates what a new solar plant displaces. The 0.220 figure is the grid average, mostly hydro, and it is what a company uses to report the emissions of the electricity it buys. The same megawatt-hour counts for three times as many tonnes in a carbon credit as in a buyer's inventory, and a model should say which factor it used.

The third route is domestic. Article 221 of Law 1819 of 2016 created the national carbon tax on fossil fuels, and Decree 926 of 2017 set out how the tax is not triggered for a fuel buyer that certifies carbon neutrality with verified reductions, obtained directly or through the end consumer. This is the no causación mechanism. Law 2277 of 2022 capped it at 50% of the tax owed. Bonos Solares, the Colombian subsidiary of First Climate, runs a program that aggregates renewable plants for this market under the COLCX standard, and it lists the 52.4 MWp Caracolí plant in Malambo, Atlántico, built by Canadian Solar, among its reference projects.

What the public numbers say per megawatt-hour

The domestic route has a hard ceiling. DIAN Resolution 000003 of 2026 set the carbon tax at COP 29,070.49 per tonne from February 1, 2026. A fuel buyer will not pay more for a credit than the tax it avoids, so at the 0.660 factor the most a solar megawatt-hour can earn here is about COP 19,190, or COP 19 per kWh. That is about 6% of the COP 315.87 per kWh at which the July 2026 auction cleared, covered in how Colombian solar sells power. Real prices sit below the ceiling. Validation, verification, and registry fees come off the top, the 50% cap limits how many credits each taxpayer can use, and solar competes with forestry projects for the same buyers.

The ceiling also rises slowly. The tax adjusts each February by the prior year's inflation plus one percentage point, until it reaches three UVT per tonne, COP 157,122 in 2026. The rate today is about 18% of that cap and gains roughly one percent a year in real terms, so the cap lies far beyond the life of any plant built now.

I-REC prices are mostly private. The most recent public figure I found is from March 2024, when Argus had Colombian hydro I-RECs of 2023 vintage on offer at about US$1.20 per MWh; current assessments sit behind a subscription. At the official TRM of COP 3,216.01 on October 7, 2026, US$1.20 is about COP 3.9 per kWh, a little over 1% of the auction price. Solar certificates may trade above hydro, and some buyers pay more for a named plant, but I have not seen a public price that changes the order of magnitude.

I found no Colombian solar project registered under VMR0017 yet, so the voluntary market has no price to quote.

At public prices, then, attribute revenue is a single-digit share of what a plant earns from power. A model that carries more than that should show where its price came from.

The additionality condition

For the voluntary market, the conditions matter more than the price. VMR0017 requires every project to pass an additionality assessment under Verra's VT0008 tool. Under the ICVCM decision, a project that wants the Core Carbon Principles label must also show, in a benchmark analysis, that carbon credit revenue increases its economic performance decisively and lifts its financial indicator to or above the required benchmark.

That puts two documents in tension. A sponsor raising equity shows a model in which the plant clears its hurdle. A sponsor registering for credits files an analysis saying the plant needs the credits to clear it. Both hold only if the investor model depends on the credits, in which case the credit price and volume carry real weight in the case. Read the investment memo and the registration file side by side.

Additionality tests look at the decision to build. A project still raising capital has an easier case to make than an operating plant that was financed on power revenue alone.

Who owns the attribute

The offtake contract decides, and the answer varies by route.

In a bilateral PPA with a corporate buyer, the certificates are often why the buyer signed. They usually travel with the energy and are priced into it. A sponsor that plans to sell I-RECs or credits from a plant with a corporate PPA should be able to point to the clause that allows it.

In a rooftop or C&I portfolio under CREG 174, most output is consumed on site, as covered in behind the meter. The host is paying for solar on its own roof and often expects to report it. If the asset owner plans to keep and sell the certificates, the PPA has to say so, and the host's sustainability team has to accept it.

For the July 2026 auction contracts, read the standard contract. I have not found public guidance on whether certificates follow the energy to the distributors that bought it or stay with the generator.

A megawatt-hour should back one claim per buyer. Verra's VCS Standard asks a project to disclose any other GHG-related environmental credit it has sought or received for the same activity, and a plant enrolled with both ECSIM and a carbon program should be able to show which megawatt-hours each claim draws on.

Rules still moving

The GHG Protocol is revising its Scope 2 guidance, which governs how companies use certificates. The public consultation on its proposals closed on January 31, 2026, and the 2015 guidance stays in force until a revised standard is published. The proposals include hourly matching and a requirement that certificates come from the same grid as the load. Under hourly matching, a solar certificate covers daytime hours only, which makes it less useful than a hydro certificate to a buyer running 24 hours a day.

The carbon tax is set by statute, and Congress already tightened the no causación route once, in 2022. A model that relies on selling credits into that market is exposed to the next tax reform.

Development finance adds a third angle. Some concessional lenders reward measured climate impact. The IDB loan FDN signed in 2025, described in who lends to Colombian solar, brought FDN into IDB CLIMA, a pilot that pays rewards tied to the climate impact of the projects it finances. Ask whether the reductions a project reports to a lender are also being sold as credits.

What to diligence

1. Which registries the plant is enrolled in (ECSIM, EcoGox, COLCX or another domestic program, Verra), for which megawatt-hours, and from what date.
2. For each offtake contract: who owns the certificates and credits, and whether their value is already in the energy price.
3. Where the model carries attribute revenue: the price source and its date, whether it is a signed contract or an assumption, the emission factor used, and the cost of validation, verification, and registry fees.
4. For a registration under VMR0017: the additionality analysis next to the investment memo, and whether the two describe the same project.
5. For credits sold into the carbon tax market: the buyer, the term, the price, and what happens to the price if the 50% cap or the rate changes.
6. For rooftop portfolios: what each host was told about who reports the solar.

What to watch

I am watching three things through 2027. First, the first Colombian solar project to list on the Verra registry under VMR0017. From January 1, 2027, every grid-connected renewable project requesting registration has to use it, and that first file will show how an additionality case reads for a Colombian plant. Second, the final GHG Protocol Scope 2 standard, which will decide how much a daytime solar certificate is worth to a corporate buyer. Third, DIAN's February 2027 rate adjustment and any reform that touches the 50% cap.