The logic of contracting in the free energy market is undergoing a profound — and silent — transformation driven by a phenomenon that has gained strength in the last three years: the intraday volatility of the Settlement Price of Differences (PLD), a value used to calculate how much each agent in the energy market should pay or receive in the short-term market.
What was once a technical detail restricted to specialists has become a determining factor in the final cost of energy consumed by companies of all sizes, especially those operating in the free market, a business model that generates around R$ 150 billion per year.
According to a new study by the energy trading company Armor Energia , which NeoFeed had access to, hourly price fluctuations, which in 2023 ranged between R$ 60 and R$ 70/MWh (megawatt-hour) during peak periods, will consistently exceed R$ 200/MWh in 2026 — and have already surpassed R$ 300/MWh in the Southeast subsystem, as recorded on January 14 of this year.
“What previously appeared as a one-off variation now reflects a profound change, marked by the growing dissociation between generation and consumption profiles throughout the day,” says Fred Menezes, sales director at Armor. “The movement is not cyclical, but structural,” he adds.
This sudden increase in price volatility reflects many of the contradictions surrounding the electricity sector.
The rapid growth of intermittent renewable energy sources—especially solar and wind—fueled by subsidies, has reshaped the dynamics of price formation in the country. During the day, strong solar generation pushes the PLD (Price of Energy in the Spot Market) down. In the early evening, when consumption rises and solar production plummets, the system needs to activate hydroelectric and, mainly, thermoelectric plants, increasing the marginal cost of operation.
This mismatch between supply and demand has created what is known as the "duck curve" in Brazil, a phenomenon already observed in markets such as the US and Australia. The result is an environment in which the average price loses relevance and hourly behavior becomes decisive for the real cost of energy.
“Even in a favorable scenario, with full reservoirs and mild temperatures, we are already seeing variations of more than R$ 200/MWh from one hour to the next,” observes Menezes, warning that, in a water crisis, this movement could amplify explosively.
Risk premium
The new dynamics have exposed weaknesses in traditional contracting models, especially "flat" contracts, based on constant supply and a fixed price. Solar generators that sold energy in this format face significant losses: they produce when the price is at its lowest and need to buy expensive energy at night to honor the contracted volume.
The risk premium associated with modulation — which previously hovered around R$ 5/MWh — now exceeds R$ 20/MWh, making the model unviable. In other words, matching the consumption profile with the generation curve becomes crucial to reduce exposure and minimize the impacts of volatility.
The crisis in the free energy market began to gain momentum in early 2024, precisely when the opening to medium and high voltage consumers was boosting expectations of expansion.
The movement occurred in a context of historically low prices, which stimulated mass migration and significant discounts, reducing electricity bills by between 15% and 30% for medium-sized companies and commercial networks. The rapid entry of these new consumers increased the management complexity for generators and traders.
This period of minimum prices, however, ended abruptly last year. The National Electric System Operator (ONS) – the body responsible for operating and coordinating the entire energy generation and transmission system in Brazil – made the pricing model more conservative in response to curtailment (cuts in energy generation from centralized renewable plants to avoid overloading the system) and the need to preserve reservoirs in the face of the intermittency of renewables and transmission limitations.
The new model prioritized greater use of thermal power plants and increased risk aversion. As a result, the computational systems—which consider hydrology, load, thermal dispatch, scarcity risk, and operational constraints—increased operating costs and intensified the volatility of the PLD (Price of Energy in the Spot Market), especially in the short term, creating the backdrop for the current crisis.
As a result, renegotiations and defaults generated a credit crisis. More leveraged companies suffered from high interest rates, curtailment , and prices incompatible with their positions.
The Electricity Sector Monitoring Committee (CMSE) is expected to define by July the risk aversion parameters that will be used in the 2026/2027 cycle — a decision that could redefine price behavior in the short term.
The increasing volatility also altered the behavior of hydroelectric plants, which reduced long-term sales to capture high prices in the short term. This contraction decreased market liquidity and made it difficult for trading companies that had lost contracts to replenish their positions. To give an idea of the scenario, the energy market experienced a liquidity drop of almost 40% in 2025.
The Armor study also points to problems in the expansion of distributed generation (DG). “Projects based on 'subscription discounts' underestimated acquisition and churn costs, increasing credit risks and attracting investors without technical experience, motivated by the ease of obtaining access approval,” warns the Armor executive. “The result was a poorly planned oversupply and greater financial exposure.”
According to Menezes, the natural path is a migration to contracts modulated by consumer spending, aligning payments with actual consumption patterns. This movement is still timid, mainly due to the difficulty in pricing risk and the low liquidity for hourly positions, but it is expected to accelerate.
Solar power generators, in turn, should seek more diversified portfolios and clients whose consumption closely matches their generation profile—such as businesses operating during business hours—reducing the need to purchase expensive energy at peak demand. Investments in batteries appear as a technical solution, but are still economically unfeasible in most cases. Thus, hourly liquidity remains the main barrier to market growth.
Menezes states that the Brazilian electricity sector is undergoing a paradigm shift. "The relationship between generation, consumption, and price throughout the day is becoming central to contracting decisions; those who don't adjust their strategy will be exposed to increasingly greater risks," he warns. In practice, in the new free market, the meter reading has become as important as the megawatt.
Capacity auction
Another controversial issue involving the electricity sector remains unresolved due to legal challenges. This concerns the approval of the results of the 2026 Reserve Capacity Auction (LRCap), held in March, which resulted in the contracting of approximately 19.5 gigawatts (GW) of power.
The objective was to contract thermal power plants fueled by natural gas, coal, fuel oil, and biodiesel, in addition to hydroelectric plants, to be activated during peak hours, between 6 PM and 7 PM, demanding firm and immediate power from the system, mainly from the thermal plants.
The auction was marred by allegations of irregularities, including an increase in the ceiling price 72 hours before the bidding. Furthermore, the volume contracted in the auction exceeded what was necessary at that time, evidenced by the very low competition – a low premium of only 5.5% – and a significant impact on electricity bills, affecting the average electricity tariff for Brazilians by approximately 10%.
The National Front of Energy Consumers (FNCE) announced on Tuesday, June 9th, that it had sent letters to the Ministry of Mines and Energy, the TCU (Federal Court of Accounts), and Aneel (National Agency of Electric Energy) reiterating its request to suspend the approval of LRCap 2026 products for power plants with longer-term contracts, for 2027 to 2031.
FNCE warns about the rapid increase in reserve charges and presents evidence of overpricing identified in the auction. The entity also recommends the adoption of measures such as Demand Response and Daylight Saving Time.
"This suspension will allow for a more in-depth examination of the technical evidence in order to ensure that there are no contracts in amounts and periods beyond what is necessary and, thus, avoid severe impacts on the cost of energy and consequently on the Brazilian economy," says an excerpt from the letter.
According to FNCE, considering the costs already foreseen in the auctions held, in 2031, energy consumers will pay R$ 49.8 billion in reserve energy charges (EER) or reserve capacity charges (ERCAP) and other similar charges, an amount greater than the budget of the Energy Development Account (CDE) in 2025.
The FNCE initiative comes a day after the Federal Court of Ceará ordered the immediate suspension of the approval of the LRCap results for 2026 and the signing of the respective Reserve Capacity Power Contracts.
The preliminary decision, however, is unlikely to prevent Aneel from approving the results this week. This is because the decision by the Ceará court is valid until the case is reviewed by the 6th Federal Court of the Federal District, where the case was referred.
Aneel understands that it had already complied with the court order and, therefore, there was no impediment to deliberating on the approval. The Federal Regional Attorney's Office of the 5th Region also stated that the condition indicated by the injunction "has already been implemented".
