With the collaboration of Vinicius Castro*
The 2025/2026 wet season ended without delivering what part of the market expected: a consistent drop in the PLD (Price of Settlement of Differences). Many consumers in the ACL (Free Contracting Environment) chose not to contract energy at the end of 2025 or the beginning of 2026, waiting for the behavior historically observed in hydrologically favorable cycles.
The premise seemed simple: more rain, full reservoirs, less thermal power, lower prices. But the Brazilian electricity sector doesn't operate based on statistical memory. It operates with probabilistic modeling, energy security criteria, and institutionally defined technical parameters. And these parameters did not indicate sufficient comfort in this cycle.
How was the 2025/2026 wet season?
The PMOs (Monthly Operation Programs), published by the ONS (National Electric System Operator), showed heterogeneous hydrological behavior among the submarkets.
Natural Inflow Energy (ENA) – % of Long-Term Average
In February 2026, the forecasts indicated approximately:
- Southeast/Central-West: 88% of MLT
- South: 52% of MLT
- Northeast: 91% of MLT
- North: 66% of MLT
In other words, a significant portion of the system operated with inflows below the historical average, especially in the South. It rained. But not enough, uniformly and consistently, to produce structural comfort.
Storage Levels
The projected storage levels at the end of February indicated approximately:
- Southeast/Central-West: 57% of maximum capacity;
- South: 42%;
- Northeast: 69%;
- North: 68%.
The Southeast/Central-West subsystem concentrates approximately 70% of the storage capacity of the SIN (National Interconnected System). Although 57% represents a recovery compared to past critical scenarios, it is still not considered a structurally comfortable level to weather the dry season with low thermal dispatch. In the South, storage levels close to 40% reinforced the need for caution.
Why didn't the price fall?
The PLD (Price of Energy in the Spot Market) is calculated by CCEE (Chamber of Electric Energy Commercialization), based on the CMO (Marginal Cost of Operation). The CMO is the result of programming and planning coordinated by ONS (National System Operator), through three main models:
- NEWAVE – Medium-term planning: Simulates future hydrological scenarios and defines the optimal water use policy. If it identifies a risk ahead, it recommends water conservation.
- DECOMP – Weekly Scheduling: Refines dispatch by considering actual electrical constraints and updated load conditions.
- DESSEM – Hourly Formation: Represents the detailed operation of the system and generates the hourly cost signal that supports the PLD (Price of Load Dispatch).
When the Electricity Sector Monitoring Committee (CMSE) adopts a conservative stance regarding energy security, the models become:
- Conserve more water;
- Maintain relevant thermal dispatch;
- Increase the expected marginal cost;
- To support higher prices.
The model doesn't react to the past. It reacts to future risk.
Perspectives for the near future
Short term (up to 3 months)
With the end of the wet season and the beginning of the dry season, the trend is:
- Maintaining a conservative stance;
- Relevant thermal dispatch;
- PLD (Price of Liquidation of Differences) remains at a high level.
Without a significant increase in storage, a sharp drop in prices is unlikely.
Medium term (2026)
Behavior throughout the year will depend on:
- Intensity of the dry season;
- Load evolution;
- Energy security criteria maintained by CMSE.
If the dry period is hydrologically adverse, the marginal cost may remain under pressure for longer.
Long term (system structure)
The sector is moving towards:
- Greater penetration of intermittent renewables;
- Greater need for consistent power;
- Emphasis on flexibility;
- Greater structural price volatility.
The average price may not be the main challenge. Variability becomes the problem.
The strategic mistake on the part of some consumers.
The problem wasn't waiting. The problem was waiting without:
- Monitor PMO;
- Evaluate ENA by submarket;
- Track thermal dispatch;
- Define exposure limits;
- Simulate financial impact.
Decisions based solely on historical data ignore the fact that each hydrological cycle is unique. Without governance, exposure becomes vulnerability.
The opportunity for integrators
This is a pivotal moment for the audience of Canal SolarThe integrator who only masters technology delivers equipment. integrator which includes:
- Price formation;
- How the models work;
- Operational indicators;
- Energy safety criteria;
- Strategic delivery.
Well-advised clients:
- They make more rational decisions;
- They avoid emergency purchases;
- They reduce financial risk;
- They consolidate long-term relationships.
The market has matured. And the integrator that matures along with it positions itself as an energy advisor.
Conclusion
The 2025/2026 wet season wasn't nonexistent. It was insufficient to generate structural comfort. And structural comfort is what consistently reduces marginal cost. The PLD (Price of Liquidation Differences) didn't fall because the system didn't enter a comfort zone.
The models responded to the risk. And the market executed the model. The objective question that remains is: Does your client make energy decisions based on institutional data or historical memory?
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Vinicius Castro He is an engineer specializing in market intelligence and risk management in the electricity sector, monitoring in real time the price formation models, the operational indicators of the National Interconnected System, and the strategic dynamics of the free market.
The opinions and information expressed are the sole responsibility of the author and do not necessarily represent the official position of the author. Canal Solar.
