Portuguese 
Four capacity reserve contracts took effect on September 1, allocating 1,712.3 MW for the power system from thermal plants in Rio de Janeiro, Ceará, Paraná, and Mato Grosso do Sul.
The group includes Termomacaé, Termoceará, Três Lagoas, and Araucária. Together with Manaus I, which was addressed separately due to its early partial operation, these five plants total 1,827.1 MW.
The early activation was recommended by the Electricity Sector Monitoring Committee to strengthen supply for 2026 and early 2027.
The decision was made in response to two combined risks: the possibility of El Niño reducing generation availability in the North and geopolitical uncertainty affecting fuel prices.
-
CCEE Corrects 800 m³/s Error in NEWAVE and DECOMP Models, Recalculating Energy Settlement Price from September 2
-
Reservoirs in Brazil’s power system drop 5.7 points in one month, reaching 69.5%, while models indicate 100% chance of El Niño lasting until 2027
-
Manaus I Thermoelectric Plant Starts Two Turbines Early, Injecting 114.8 MW into the Electric System, While the Third Unit of 48.1 MW is Scheduled for December
-
ONS Finds Zero Capacity for New Generation Projects in Northeast Brazil, Halting 8.57 GW Queue and Leaving 223 Exit Requests That Could Open Transmission Space
The contracts resulted from reserve auctions held in 2022 and 2026. With the early activation, their clauses began to take effect from the new supply start date.
Capacity reserve contracts cover part of the power gap
According to the Ministry of Mines and Energy, the 2026 auction identified a need for 4.2 GW to meet peak demand.
The auction contracted 2.2 GW, leaving a gap compared to the amount determined in the planning.
The early activation helps fill part of this gap with plants that had previously won bids and expressed interest in starting supply sooner.
In April, the Ministry consulted projects with a total capacity of approximately 3,482 MW.
Of this group, around 2,377 MW expressed interest. The National System Operator (ONS) evaluated what would be needed and which plants met operational requirements.
The final selection considered compatibility with planning studies and minimal tariff impact.
Manaus I had two turbines cleared for commercial operation, with 114.8 MW. Excluding this portion from the total of 1,827.1 MW, the other four thermal plants contribute 1,712.3 MW.
This calculation avoids counting the same plant in two reports as if they were independent additional capacities.
Viewed this way, the batch of four contracts represents the majority of the advance capacity. Manaus I adds the remaining fraction already authorized.
Capacity reserve does not mean that all machines will generate at maximum throughout the day. The system contracts availability to activate capacity when needed.
Costs of plants without contracts were at least 25% higher
The CMSE also considered dispatch pricing. According to the Ministry, reported costs from companies without contracts were at least 25% higher than those of contracted plants.
This difference weighed heavily in light of the potential for international fuel price increases. A plant without a contract can become a more expensive option when the system needs additional generation.
Early activating known contracts provides predictability regarding cost and availability, although actual operation still depends on the needs defined by the ONS.
El Niño factors into the equation as it may reduce energy produced in the North and raise temperatures. Heat, in turn, tends to increase cooling load.
Thermal power plants provide controllable generation and can respond when hydropower or variable renewable production does not meet demand.
Conversely, they rely on fuel and generate operational costs and emissions. The system’s decision weighs security, availability, and price.
The original clauses of the contracts, including penalties for delays in starting operations, took effect on September 1.
This turns anticipation into an effective obligation. The plant does not just receive the possibility of starting early; it assumes a commitment within the new schedule.
It is clear that the reserve acts as a power insurance. The cost exists even before a critical situation because the value lies in the machine available when called upon.
Termomacaé, Termoceará, Três Lagoas, and Araucária distribute the reinforcement across four states and different points of the grid.
This location helps the operator consider regional constraints and transmission flows, rather than treating the 1,712.3 MW as a block concentrated in a single place.
The effect of the reinforcement will be seen in dispatch over the coming months. If hydrology and load are favorable, part of the capacity may be dispatched less frequently.
If El Niño pressures generation and consumption, the contracts will be available under the defined conditions. This is the central purpose of the anticipation.
The system enters September with a higher thermal margin, but it does not eliminate the need to monitor water, fuel, transmission, and costs.
Termomacaé and Termoceará are located near consumption centers and gas infrastructure. Três Lagoas and Araucária add availability in other areas of the interconnected system.
The contracted power can meet peak demand even when the plants have not operated in the previous hours. This flexibility differentiates capacity from continuously delivered energy.
To remain available, each venture needs to maintain teams, conduct maintenance, ensure connectivity, and have fuel under the contractual conditions.
Penalties for delays pressure compliance with the new dates. If a machine is not ready when required, the contract outlines consequences that have taken effect with the anticipation.
The tariff cost depends not only on the contract value but also varies with the number of hours dispatched and the fuel consumed over the period.
The minimum difference of 25% compared to the non-contracted offers favored the early selection. It does not mean that thermal power plants are always the cheapest source in the system.
During hours of abundant sun and wind, other sources may meet the load at lower variable costs. The reserve gains value when these conditions do not align with demand.
The 1,712.3 MW must be added to the other available resources, not compared in isolation against the total need of 4.2 GW from the auction.
The decision anticipates already contracted assets but does not replace future expansion. The system will continue to need planning for the coming years.
September will be the first test of this new arrangement.
Does the security of 1,712.3 MW of thermal power justify the cost of keeping these plants available?
