Behind the Meter: How a Colombian Rooftop Solar Asset Gets Paid Under CREG 174

Executive summary

A utility-scale Colombian solar plant sells electrons. A rooftop system does something different: it stops its host from buying them. Everything about how a residential or commercial-and-industrial solar portfolio earns revenue in Colombia follows from that distinction.

The regulation that governs this is CREG Resolution 174 of 2021, dated October 7, 2021 and published in the Diario Oficial on November 23, 2021, which replaced CREG 030 of 2018. It defines the small-scale self-generator, the AGPE, as anything under 1 MW, sets the connection rules, and decides what a kilowatt-hour pushed back into the grid is worth. That value depends on the system's size and on whether the site exported more than it imported in the billing month, and it ranges from nearly the full retail tariff down to the hourly spot price.

This piece covers the tariff a rooftop asset displaces, the crediting mechanics, the 2025 and 2026 changes that matter for portfolio design, and what to diligence.

The number being displaced

Colombia's regulated electricity tariff is built from six components under a formula CREG has maintained since 2007: generation (G), transmission (T), distribution (D), commercialization (Cv), losses (PR), and restrictions (R). Portafolio, citing former energy minister Diego Mesa, put their approximate weights at 33% generation, 37% distribution, 9% commercialization, 8% restrictions, 7% losses, and 6% transmission.

The full unit cost, the costo unitario or CU, is what a regulated user without subsidy pays. In August 2026, per the tariff schedules compiled by OPS Colombia from each operator's published rates, that was COP 984 per kWh for Celsia in Valle del Cauca, COP 960 for EPM in Antioquia, COP 890 for Air-e on the Caribbean coast, and COP 864 for Enel in Bogota. At the August 2026 average TRM of about COP 3,130 per dollar, that is roughly 28 to 31 US cents per kWh.

Compare that with what the July 2026 long-term auction cleared at for utility-scale solar: COP 315.87 per kWh, as covered in how Colombian solar sells power. A rooftop kilowatt-hour consumed on site is worth close to three times a utility-scale kilowatt-hour sold under a 15-year contract, because it displaces the whole delivered tariff, not just the generation component. That spread is why distributed solar in Colombia can be financed at all, and why the crediting rules matter: the moment a kilowatt-hour leaves the site, the value it captures drops.

Three kinds of kilowatt-hour

CREG 174 treats the output of an AGPE using renewable sources in three tiers, and the tiers are where most models go wrong.

The first tier is energy consumed at the moment it is generated. It never crosses the meter in the export direction, so no charge applies; the host simply buys fewer kilowatt-hours. For a commercial site with daytime load, a factory, a cold-storage warehouse, a supermarket, most of the output lands here, and this is the kilowatt-hour that captures the full CU.

The second tier is surplus exported during the billing period up to the amount the site imported in that same period. CREG 174 calls this excedentes tipo 1 and treats it as an energy credit: each exported kilowatt-hour is netted against an imported one. For an AGPE under 100 kW, the retailer charges the commercialization component on each credited kilowatt-hour, so the credit is worth the CU minus Cv. For an AGPE between 100 kW and 1 MW, the retailer also charges transmission, distribution, losses, and restrictions, and the credit is worth essentially the generation component alone, roughly a third of the retail tariff.

The third tier is surplus beyond what the site imported, excedentes tipo 2. The retailer pays for it at the hourly spot price on the bolsa. Per the monthly averages OPS Colombia tracks for 2026, that ran from about COP 124 per kWh in February to COP 562 in June. A model that values all exported energy at the retail rate has overstated that portion by a factor of about 1.5 in June and nearly 8 in February.

Read together, the tiers give the design rule for a Colombian rooftop portfolio. Value comes from self-consumption first, netted surplus second, and net export last. Size each system to the host's daytime load. Capacity added to sell power back to the grid earns the spot price.

The thresholds that change the asset

Two capacity lines matter, and they are not the same line.

The 100 kW line inside CREG 174 determines which charges apply to credited surplus. It also sits close to the boundary between regulated and non-regulated users, which CREG defines at 100 kW of demand or 55 MWh per month. A non-regulated user negotiates its supply contract directly rather than paying the published CU, so the tariff a PPA discount is measured against is a negotiated one. Diligence on a C&I portfolio has to establish that tariff host by host.

The 1 MW line is the ceiling of the AGPE category. Above it, a project is a large-scale self-generator under the commercial rules for conventional generation, with connection through UPME for larger sizes, as described in the piece on Colombia's grid connection queue. Below it, the counterparty for connection is the operador de red, and CREG 174 sets a three-stage procedure: documentation, technical review, and an operational entry request through the operator's online window. The sequence is fixed; the operators' turnaround times are not, and a portfolio's construction schedule depends on them.

What changed in 2025 and 2026

Two regulatory moves since the site last covered how solar financing works in Colombia bear directly on portfolio design.

CREG 101 072 of 2025, the energy communities resolution, also rewrote the pricing basis for excedentes tipo 2. Instead of the hourly spot price, surplus was to be paid at the MCm, the weighted average price of the retailer's contract book, which is far less volatile than the bolsa. CREG 101 087 of October 30, 2025, published in the Diario Oficial on December 10, then kept the transitional spot-price provision in force until CREG issues a separate methodology for allocating MCm costs, with retailers required to update contracts from the third month after that methodology takes effect. As of August 2026 the transition had not happened. Net-export revenue is spot-priced today and may move to a contract-price basis on a date the regulator has not set. Model it at spot and treat the MCm shift as an upside scenario, not a base case.

CREG 101 072 also settled how collective self-generation, the AC structure inside an energy community, is paid. Capacity tiers decide whether an AC is settled under the AGPE rules or the commercial rules for larger generators, and the resolution sets how surplus is shared among participants. With those rules in place, an energy community's output can go into a cash flow model.

The second move is CREG 101 099 of February 19, 2026, which operationalized remote self-generation (autogeneración de forma remota, AGFR in the resolution's terms) under Decree 1403 of 2024. A consumer can now own a plant at one location and credit its output against consumption at another, transported across the national grid. Transmission charges apply throughout, and the CERE and FAZNI contributions are waived only in hours when generation is at or below consumption. Backup contracts are mandatory at 100 kW and above, and both the generation and consumption points register as commercial frontiers with the market administrator. The plant owner has to serve itself or directly linked entities, so the structure suits a corporate group with many sites. For a C&I portfolio, it removes the roof as the binding constraint on system size.

What behind-the-meter revenue depends on

Strip the regulation away and the revenue of a Colombian rooftop asset rests on four things.

The host's load profile, because only coincident consumption earns the full tariff. A site that runs at night and exports by day earns spot prices on a rooftop cost base.

The tariff being displaced. Distribution is the largest component and is reset by CREG per operator on multi-year periods. Generation is the volatile component and follows hydrology, so a behind-the-meter asset carries the same El Nino exposure the utility-scale sector does, in the opposite direction: dry years raise the value of every self-consumed kilowatt-hour.

The host's credit. The counterparty in a rooftop PPA is not XM, not a retailer, and not the regulated demand pool. It is the business or household under the panels, for the life of the contract. A portfolio of 200 hosts is 200 credit decisions, and a fund that describes its risk as "regulatory" without describing its offtaker underwriting has not described the risk.

The currency. Every component of the CU is set in pesos. The framework in currency risk and the Colombian solar opportunity applies as written, with one addition: some C&I hosts earn in dollars, and a PPA indexed to the TRM with an exporter or a multinational moves the exposure to a counterparty better placed to carry it.

What to diligence

1. For each host, what share of modeled output is self-consumed, netted, or net-exported, and at what price is each tier valued? A model that shows one blended price per kWh has not done this.
2. Is each system under or over 100 kW, and does the model apply the correct charges to credited surplus for its size?
3. Is the host regulated or non-regulated, and what is the actual tariff, published CU or negotiated contract, that the PPA discount is measured against?
4. How is the distribution component escalated, and does that match the network operator's current CREG tariff period?
5. Is net-export revenue modeled at spot or at MCm, given that CREG 101 087 left the spot basis in force?
6. For any energy community or remote self-generation structure, has the AC or AGFR registration been completed with the operator, and is the backup contract in place where capacity reaches 100 kW?
7. What is the host's credit, how was it underwritten, and what happens to the asset if the host leaves the site?

What to watch

The date CREG issues the MCm methodology, which will move net-export pricing off the bolsa. The distribution tariff resets by operator, which reprice the largest component of what these assets displace. And the first remote self-generation portfolios registered under CREG 101 099, which will show whether the structure works at scale.

The resource is strong: 5.5 kWh per square meter per day on the Caribbean coast, and retail tariffs among the highest in Latin America. CREG 174 and its amendments determine how much of that value a distributed asset keeps, and the answer runs from nearly all of it for a kilowatt-hour consumed on site to about a seventh for one exported in a low-price spot month.