April 22, 2026

Expensive Insurance: Tariff Effects of the Capacity Reserve Auction

Summary

The results of March's Capacity Reserve Auction incorporated a risk premium consistent with the urgency of the contracting process, adding a new and heavy layer of structural costs for society, on the order of BRL 48 billion per year by the start of the next decade. This TR Soluções analysis shows that these costs are expected to produce a growing tariff effect starting this year, reaching an average level of 8.4% in 2032, once all the capacity contracted last month is available. Notably, the weight on bills won't be uniform across different consumers, hitting large industries proportionally harder. The structural impact of this bill serves as a warning: the security of the National Interconnected System (SIN) can no longer depend exclusively on contracting thermal power plants.

1. Introduction

March's Capacity Reserve Auction marked a turning point in how Brazil handles power-supply security, contracting nearly 20 GW of capacity to guarantee service during peak-demand moments.

The need for this type of contracting isn't a recent diagnosis. The first formal warnings from official planning on the subject date back to technical notes published in 2012. The long gap between identifying the problem and actually going to market to buy this "insurance" limited the State's room to maneuver.

As a result, by seeking supply close to the system's projected criticality limit, contracts ended up incorporating a risk premium consistent with the urgency of the contracting process. The result is that the auction adds a new and heavy layer of structural costs for society.

This analysis assesses these costs — which will be funded through the Capacity Reserve Power Charge (ERCAP) — and estimates how they might impact energy tariffs in the coming years.

Among the findings, it's worth noting that the weight on different consumers' energy bills won't be uniform, resulting in a tariff-impact asymmetry that will proportionally penalize more severely consumers connected at higher voltage levels.

According to projections from SETE, TR Soluções' tariff-projection and market-intelligence model, this escalation will produce an unprecedented effect on tariff composition: starting in 2029, all high-voltage consumers (above 69 kV) in the S and SE-CO submarkets are expected to see an ERCAP-related tariff higher than the tariff for the Energy Development Account (CDE Usage) component.

2. The Evolution of Capacity Requirements in Planning

Historically, ensuring load service in Brazil was guided by the energy balance. Power — understood as the system's instantaneous response capacity to meet peak demand — was treated as an attribute intrinsic to supply contracts, especially those tied to captive consumers: the predominance of hydroelectric plants with large storage reservoirs guaranteed that, by contracting energy, capacity "came along with it."

However, the transformation of Brazil's power mix — marked by declining reservoir regulation capacity and the massive addition of variable renewable sources — changed this dynamic. Abundant energy (MWh) stopped guaranteeing capacity adequacy (MW) during the system's periods of highest demand.

This realization was institutionalized by the Energy Research Company (EPE) through Technical Note EPE-DEE-RE 037/2012-r0. From then on, the Ten-Year Energy Expansion Plans (PDE) began recording, with growing intensity, the gap between supply and capacity needs:

• PDE 2020: introduction – start of systematic monitoring of the capacity balance and formalization of the chapter on peak demand.
• PDE 2022: consolidation – the 2012 Technical Note's methodology was adopted as the official standard for assessing peak-hour risks.
• PDE 2023: warning sign – diagnosis of a high probability of a capacity shortfall within a 10-year horizon, with moderate impact.
• PDE 2024: model crisis – a stark warning that expansion based on energy alone is insufficient, and a call for additional supply specifically for capacity.
• PDE 2026: definitive change – capacity stopped being just a monitoring item and became a mandatory constraint in the system-expansion model.

Despite this growing planning guidance, the legal framework to enable contracting specifically for this attribute was only finalized in the early part of this decade. Law No. 14,120/2021, resulting from the conversion of Provisional Measure No. 998/2020, enabled the publication of Decree No. 10,707/2021, which regulated capacity reserve contracting in the form of power and established the ERCAP.

Under this legal framework, the first Capacity Reserve Auction was held in December 2021, contracting about 4,600 MW of capacity at an average price of BRL 744,026 per MW made available, already factoring in thermal plant efficiency criteria. The auction held in March 2026, then, doesn't launch the model — it consolidates a supply strategy that, although planned for more than a decade, had its implementation delayed until the limit of the system's operating safety.

This trajectory, however, wasn't hampered only by hesitation within the Executive Branch, but also by litigation in the power sector. The government's schedule called for intermediate contracting rounds, but the attempt to hold the auction planned for 2025 ran into a precautionary suspension in court.

The litigation, driven by challenges to the bidding rules, culminated in the halt and subsequent cancellation of the process by the Ministry of Mines and Energy (MME) itself, stalling the agenda for expanding system security. This legal obstacle widened the regulatory gap that compressed the schedule, pushing the actual capacity contracting to the limit of systemic need this year.

3. Analysis Methodology: Tariff Composition Across Voltage Levels

Before measuring the isolated effect of capacity contracting, it's necessary to understand the composition of electricity tariffs in Brazil. For this exercise, TR Soluções broke down the average tariff of the country's 51 distribution concessionaires into five broad cost groups: energy, transmission, distribution, charges, and losses.

• Energy: represents the average price of the distribution companies' purchasing portfolio, encompassing Energy Trading Contracts in the Regulated Environment (CCEAR), Itaipu energy, Angra 1 and 2 quotas, Firm Capacity Quota Contracts (CCGF), bilateral contracts, and self-generation. This component's price varies very little between tariff subgroups, since energy cost doesn't depend on the consumer's size, but on the distribution company's contractual mix.
• Transmission: pays for basic grid services, including connections, usage contracts, and Itaipu's transmission lines. Values differ between distribution companies due to geographic location and the amount of border assets, and there are also distinctions in how costs are split among voltage levels.
• Distribution: covers operating, maintenance, and service-remuneration costs for the distribution company. It's allocated across voltage levels based on marginal capacity cost. Since it reflects each voltage level's responsibility for using pole, wire, and transformer infrastructure, it's the tariff component that shows the greatest variation depending on supply voltage.
• Charges: consolidates sectoral charges billed under the Distribution System Usage Tariff (TUSD) and the Electricity Tariff (TE). There are differences in billing arising from the consumer unit's voltage level and the submarket the concessionaire is connected to.
• Losses: covers technical, non-technical (theft), and basic-grid losses, whose costs are also allocated to consumers differently depending on supply voltage.

The difference in the final amount paid by consumers stems primarily from the physical infrastructure required. At the far end of this requirement sits retail. Table 1 details the composition for residential consumers and small commerce and industry (subgroups B1 and B3).

For electrons to reach these units, the entire upstream distribution grid infrastructure must be used. Although, on the Brazil average, energy cost is still slightly higher than distribution cost for these consumers, at some specific distribution companies the tariff that pays for that service already stands out as the most significant element of the electricity bill.

Source: SETE Platform, by TR Soluções.

Distribution infrastructure requirements decrease for medium-voltage consumers. Table 2 presents the average composition for subgroup A4 (connected between 2.3 kV and 25 kV), which represents an intermediate point in terms of responsibility for distribution grid usage.

Source: SETE Platform, by TR Soluções.

In contrast, large industrial consumers connected at high voltage face a completely different tariff reality. Table 3 shows the cost structure for subgroup A2 (connected at 138 kV). Because they access the grid at high voltage levels, these agents don't use the grids downstream of their connection voltage level. As a result, they pay more in sectoral charges than the sum of their spending on distribution, transmission, and losses.

Source: SETE Platform, by TR Soluções.

This cost structure, combined with the ERCAP rules detailed below, should result in a proportional asymmetry in the effects caused by the auction.

3.1 ERCAP Allocation

Unlike the allocation criteria adopted for all other tariff components, ANEEL provisionally defined for the ERCAP that the fixed revenue of the contracted plants is allocated proportionally to each consumer's maximum hourly consumption during the assessment month.

Since this measurement happens over a specific one-hour interval, in practice the mechanism works like a capacity charge (BRL/MW). To close the monthly account, the Electric Energy Trading Chamber (CCEE) "stacks up" all recorded peak demands and charges each consumer's share based on their participation in that total, regardless of whether their individual peak coincided with the system's period of greatest stress.

This choice of allocation criterion sparked intense debate in the sector — enough, on its own, to warrant a dedicated article — but its practical effect on the bill is unavoidable: when this charge is added to a large A2 subgroup consumer's tariff, the perceived percentage effect is markedly more severe than what a residential consumer feels.

4. LRCAP Results

In March, 19,478 MW of available capacity were contracted. Of that volume, 403 MW were contracted for a three-year period, 7,707 MW for ten years, and the largest share, 11,368 MW, took on 15-year supply commitments. The average price was BRL 2,011,824 per MW made available. The projects' commissioning schedule is shown in the table below.

Own elaboration based on CCEE data.

To gauge the weight of this "insurance" for serving the system's peak in isolation, disregarding variable costs, TR Soluções specifically analyzed the projected fixed revenue to be paid to the generators that were awarded these contracts.

In nominal terms, the sum of these commitments could imply a financial requirement close to BRL 53 billion (BRL 5.1 billion from the 2021 auction and BRL 47.7 billion from last month's auction) by 2032, when all the contracted capacity will be fully available and being remunerated.

Source: SETE Platform, by TR Soluções.

If this fixed revenue were allocated linearly by the average consumption of the entire SIN, the ERCAP would impose a uniform cost of approximately BRL 78.00/MWh consumed. But this calculation is merely an illustrative exercise: in practice, as detailed above, CCEE carries out the allocation following ANEEL's regulation, which is based on stacking the maximum demand required by each consumer unit. Still, this volumetric simplification is useful for comparing the size of the ERCAP with the tariffs and charges already known and presented in the previous section's tables.

The scale of this BRL 53 billion consolidates a new and challenging cost paradigm. By reaching this magnitude, the fixed revenue to support the capacity reserve rivals the size of the Energy Development Account (CDE), the sector's "super charge," which recently broke through the worrying BRL 50 billion annual mark.

If, over the last decade, the power sector's great national debate centered on the almost unsustainable weight of subsidies and public policies embedded in the CDE, the horizon of the next decade may be marked by the rigid cost of physical supply security. The delayed response to planning, made worse by litigation that suspended previous auctions and forced the government to cancel bidding rounds, exacted its urgency premium, resulting in a scenario where Brazilian consumers will now simultaneously fund, in the billions, both CDE subsidies and ERCAP's capacity insurance.

4.1. Tariff Impacts of the ERCAP

Considering the tariff composition presented in section 3, the SETE model shows that the capacity reserve contracted in March 2026 alone will have an average impact on application tariffs of about 0.4% this year. By 2032, the scenario changes drastically, to an effect of 8.4% on the Brazil average tariff.

This comparison of the projected national average application tariff (comprising the sum of TUSD and TE) for 2032, in scenarios "with" and "without" including the results of the 2026 auctions, reveals a considerable effect on consumers at all voltage levels.

For residential consumers (subgroup B1), the perceived effect represents an average increase of 7.5% in the final application tariff. Moving to medium voltage (subgroup A4), the impact becomes more significant, reaching 10.3%.

The largest relative shock, however, falls on large industrial consumers connected at high voltage (subgroup A2), who could see an impact of 13.5% on their tariffs compared to a scenario without the capacity auctions held in March 2026.

5. Final Considerations

Projections from the SETE model indicate that capacity reserve contracting — adding the commitments from the pioneering 2021 auction to the results from March 2026 — carries a structural financial weight of approximately BRL 53 billion per year by the start of the next decade. As detailed in this study, the total cost of this systemic security will represent a reference ERCAP in the range of BRL 78.00/MWh in 2032.

This cost will fall asymmetrically on society, raising the operating-cost floor for high-voltage-connected industry more than others and pushing the ERCAP to a magnitude equivalent to, or in some cases greater than, the CDE.

On the other hand, however substantial the pass-through of this "urgency premium" may be given the system's capacity shortfall, it's worth remembering that a blackout would represent a far more tragic and costly scenario for society. The regulatory and economic premise that the most expensive insurance is the one you don't have remains valid.

Either way, the structural impact of this bill serves as a warning: the security of the National Interconnected System (SIN) can no longer depend exclusively on contracting thermal power plants. Modernizing price signals and building robust demand-response mechanisms have become unavoidable, so that consumers themselves have adequate economic incentives to flatten their peak consumption, mitigating the need for future, costly emergency contracting.

6. Methodological Caveats

The analytical exercise conducted by TR Soluções is strictly tariff-related in scope. Its aim was to isolate and measure the pass-through of the new fixed revenue allocated to electricity bills.

The analysis doesn't consider the macroeconomic impacts of a failure to meet peak demand or the extremely high cost of an eventual physical rationing scheme.

Additionally, the financial impacts and capacity volumes presented in this study represent a snapshot of the current contracting scenario, and may change due to future auctions.