September 2, 2025

The Tariff Weight of Overrides to Energy Planning

Helder Sousa

Gabriel Lemos

Fabiano Dias

Summary

Since 2021, the power sector has been the stage for political battles with a direct impact on expanding the energy supply. These are legal and infra-legal provisions that introduced mandatory contracting of generation from specific sources, with predefined timelines, locations, and volumes, disregarding sector planning's technical guidelines.

This study describes the main moves made by the Executive and Legislative branches regarding mandatory energy contracting, and shows that their average tariff impacts can vary significantly, especially for free consumers, who feel the actual monthly variation in the Reserve Energy Charge as it's calculated during short-term market settlement. But regulatory uncertainty suggests the picture is far from settled.

The analysis, beyond a reference outlook, considers three scenarios:

1. Simulates contracting the thermal plants provided for in Law No. 14,182/2021 through the reserve-energy mechanism, as originally envisioned (disregarding contracting in the North region, for which there was no energy supply). It also considers the additional contracting of 1,009 MW of hydroelectric plants up to 50 MW, since 175 MW was already contracted in the 37th New Energy Auction (LEN) and 816 MW in the 39th LEN, held on August 22, 2025.
2. Considers Congress fully overriding the Presidency's vetoes to Law No. 15,097/2025 (the offshore wind generation framework), with mandatory contracting of the 8,000 MW of gas-fired thermal plants and an increase to 4,900 MW in hydroelectric-plant contracting, plus 250 average MW of hydrogen energy from ethanol in the Northeast, 300 average MW of wind energy in the South region, and 1,732 average MW of coal-fired plants whose regulated contracts end by 2028.
3. Considers contracting only 3,000 MW of small hydroelectric plants for delivery in 2032, 2033, and 2034, as reserve energy. No other contracting was considered, given the limitations imposed by MP 1,304/2025, except for that already carried out under Law No. 14,182/2021.

1. Introduction

Law No. 14,182/2021, which authorized Eletrobras' privatization, kicked off a series of changes to power-sector rules, with a direct impact on planning for expanding the electricity supply. These are legal and infra-legal provisions that introduced mandatory contracting of generation from specific sources — especially inflexible thermal plants and small hydroelectric plants — with predefined timelines, locations, and volumes, disconnected from sector planning's technical guidelines.

While Law No. 14,182 provides for the granting authority to contract 8,000 MW of natural-gas thermal plants and 2,000 MW of hydroelectric plants up to 50 MW, the passage and later enactment of Law No. 15,097/2025, on 1/10/2025, as well as the publication of Provisional Measure No. 1,304/2025, on 7/11/2025, reflect attempts to adjust these provisions, expanding, repealing, or reworking the targets and contracting mechanisms. This process created regulatory overlaps, gaps, and uncertainty about how part of these obligations should be operationalized, significantly affecting their respective consequences.

This article describes the main moves made by the Executive and Legislative branches regarding mandatory power-generation contracting since 2021. Beyond reconstructing the chronological and legal facts, it presents and comparatively analyzes projections of these measures' potential tariff impacts, considering the legislation in force and the infra-legal provisions available so far. This is an attempt to shed light on the effects of a regulatory trajectory marked by overlaps, repeals, and reworkings, whose consequences invariably fall on consumers.

2. Background

This section presents the main legal provisions addressing mandatory electricity contracting since 2021.

2.1. Law No. 14,182, of 7/12/2021 (Law 14,182) – Eletrobras Privatization

The first paragraph of Article 1 of the law required the granting authority to contract natural-gas thermal plants under the capacity-reserve-in-the-form-of-energy modality, totaling 8,000 MW distributed regionally, with a minimum inflexibility of 70% and a 15-year supply term. 1,000 MW would be contracted in the Northeast, 2,500 MW in the North, 2,500 MW in the Center-West, and 2,000 MW in the Southeast. Of that total, 2,000 MW (or 1,400 average MW, factoring in inflexibility) were offered in the 2022 Capacity Reserve Auction in the Form of Energy (LRCE), with 670 average MW contracted in the North Region.

Additionally, Article 21 of the law determined that, in the A-5 and A-6 Auctions, at least 50% of the demand declared by distribution companies must be allocated to contracting hydroelectric plants with capacity up to 50 MW, until the total volume of 2,000 MW from that source is reached, with a participation cap per state and a price ceiling set based on the 2019 A-6 Auction values.

2.2. Law No. 15,097, of 1/10/2025 (Law 15,097) – Offshore Generation Legal Framework

The law essentially rewrote the first paragraph of Article 1 of Law 14,182, adding new contracting requirements. The text approved by Congress established, beyond the original provisions, the following additions: an increase in the amount of hydroelectric plants up to 50 MW to be mandatorily contracted, as reserve energy; contracting 250 average MW of energy from liquid hydrogen derived from ethanol in the Northeast; and 300 average MW of wind power in the South, among others, as detailed below.

In the first case, the provision raised the hydroelectric-plant contracting target from 2,000 MW to 4,900 MW, changing the mechanism from a regulated auction to reserve energy. This section was approved by Congress and vetoed by the Presidency, but Congress overrode the veto on 6/17/2025, bringing it into force. However, the veto to the provision defining the contracting model as reserve energy wasn't reviewed at the same time. In other words, the obligation to contract these plants' energy was created without defining which mechanism should be used.

Regarding contracting hydrogen and wind energy, that section was also fully vetoed by the Executive, on the grounds of hydrogen's still-nascent technological development and uncertain costs. But Congress also overrode that veto, reinserting the obligation into the law. However, the legal text doesn't specify the applicable contracting model. In practice, complying with this requirement will depend on infra-legal regulation from the Executive, which will need to define not just the contracting model, but also the funding mechanisms and the allocation of the corresponding sectoral charges.

Another relevant aspect of the law was the requirement to extend, through 2050, the operation of domestic coal-fired thermal plants contracted via regulated auction (Article 13, item V, of Law No. 10,438/2002) and those with contracts through 2028, setting 70% inflexibility and new remuneration bases — now under the reserve-energy model rather than with Energy Development Account (CDE) subsidies. In short, the goal was to ensure the continuity of existing coal plants for more than 20 years. This section was vetoed by the Presidency on the grounds of conflicting with climate commitments and having a negative tariff impact. Congress hasn't yet reviewed that veto; therefore, the coal-plant extensions aren't in force.

The Conversion Bill that resulted in Law 15,097 also included, through §§12 and 13 of Article 1 of Law 14,182, a proposal to mandatorily redistribute natural-gas thermal plants within the originally planned 8,000 MW. These provisions, however, were vetoed by the Executive Branch on the grounds that the timelines and locations would lock down sector planning and could bring additional costs for logistics infrastructure, such as gas pipelines, to be shared among consumers. So far, the vetoes to these paragraphs haven't been reviewed by Congress, so they haven't taken legal effect.

2.3. Provisional Measure No. 1,304, of 7/11/2025 (MP 1,304)

MP 1,304 changes the picture again, easing the requirements imposed by the previous laws. The provisions most relevant to TR Soluções' study are:

• Replacing gas-fired thermal plants with hydroelectric plants up to 50 MW: MP 1,304 amends Law 14,182 to remove the requirement for 8,000 MW of inflexible thermal plants and insert, under §19 of Article 1, contracting 3,000 MW of hydroelectric plants up to 50 MW, staggered across three capacity-reserve auctions between 2032 and 2034. In addition, MP 1,304 inserts Article 1-A into the same law, establishing that any mandatory energy contracting must be limited to the need identified by sector planning, according to technical and economic criteria set by the National Energy Policy Council (CNPE), except for the hydroelectric contracting under §19 (which was explicitly exempted from that condition).
• Repealing previous hydroelectric-plant rules: MP 1,304 expressly repeals Articles 20 and 21 of Law 14,182, removing from the legal framework the former requirement to allocate 50% of auction demand to small hydroelectric plants up to the 2,000 MW cap. This formalizes the replacement: out goes the original model, and in comes the new 3,000 MW program via capacity reserve, indicated above.

But although MP 1,304 required contracting 3,000 MW of hydroelectric plants through capacity-reserve auctions, there's still some confusion, and even uncertainty, over the definitive contracting format for these plants. Although it makes more sense to tie them to meeting power (MW) demand, there are elements in the legal text indicating this is actually contracting under the capacity-reserve model in the form of energy (MWh). Among these elements are the link between the contracting and the reference price of the 2019 A-6 Auction, structured with high inflexibility, and the absence of provisions referencing the typical power-based regime (such as those set out in Decree No. 10,707/2021). So although the term "capacity reserve" at first glance suggests allocation through the Capacity Reserve Power Charge (ERCAP), TR Soluções' interpretation is that the costs of this contracting will be borne by consumers via the Reserve Energy Charge (EER), as happens in the traditional reserve-energy model tied to inflexibility.

In short, over four years, Article 1 of Law 14,182 has been, and still is, the main battlefield for legislative disputes and executive-branch course corrections regarding mandatory electricity contracting. Since its enactment, the provision has been deeply changed: it initially required contracting 8,000 MW of natural-gas thermal plants with a minimum inflexibility of 70%, distributed regionally; it was then expanded to include hydroelectric plants up to 50 MW (totaling 4,900 MW) and generation from green hydrogen, wind, and coal. After vetoes and partial repeals, MP 1,304 eliminated the gas-fired thermal plant requirement and established a new program to contract up to 4,900 MW of small hydroelectric plants (of which 3,000 MW mandatory), through auctions staggered between 2032 and 2034. In the same move, it imposed limits on future mandatory contracting outside sector planning, signaling an effort to reverse the effects of previous decisions marked by low viability and high tariff impact.

3. Scenarios and Their Tariff Impacts

To estimate the tariff impacts of the main legislative changes discussed in previous sections, TR Soluções simulated three distinct scenarios, each representing the implementation of the legal and infra-legal provisions in force or under discussion, compared against a reference scenario. The projections — based mainly on the evolution of reserve energy's annual fixed revenue — were made for a horizon through 2035, the year in which, under the assumptions adopted, all planned mandatory contracting would have already been implemented or concluded. The tariffs and figures presented are all in nominal terms. Below are the details for each scenario.

3.1. Reference Scenario

This is the standard scenario from version 14.93 of TR Soluções' Energy Tariff Estimation Service (SETE), using the platform's standard assumptions and disregarding the effects of contracting not carried out under Laws 14,182/2021 and 15,097/2024 and Provisional Measure 1,304/2025, specifically regarding the energy contracting covered in this article.

In this scenario, reserve energy's annual fixed revenue follows the trajectory shown in Figure 1, reaching a bit more than BRL 15 billion in 2035. It's worth noting this case doesn't factor in any renewal of ordinary reserve-energy contracts.

Source: TR Soluções' SETE platform.

Among the changes made by the laws and the provisional measure covered in this article, the element most affected is reserve energy. From Figure 1, we have:

• LER: ordinary Reserve Energy Auctions held through September 2016;
• PCS: the Simplified Competitive Procedure, known as the "emergency auction," which contracted energy to tackle the 2021 water crisis, with supply originally set to start in May 2022 and end in December 2025, totaling 44 months. But, due to operational and administrative issues involving the National Electric Energy Agency (ANEEL), the Ministry of Mines and Energy (MME), and the Federal Court of Accounts (TCU), an agreement was reached allowing part of the PCS supply to extend through 2032;
• MP No. 1,232/2024: addressed converting natural-gas thermal-plant contracts with the distribution company Amazonas Energia into reserve-energy contracts;
• LRCE: the Capacity Reserve Auction in the Form of Energy already held in 2022, which contracted 670 average MW for the North region.
• Law No. 14,299/2022: enabled contracting the Jorge Lacerda Thermal Complex (CTJL) as reserve energy.

Disregarding taxes and any tariff-flag additions, in this scenario Brazil's average residential tariff, weighted by the market of the 51 Brazilian concessionaires, reaches BRL 1,173/MWh in 2035. This tariff served as the reference for estimating the impacts of the other scenarios described below.

It's important to stress that reserve-energy generation costs are paid by consumers through the EER. This, in turn, depends on the short-term market price (PLD), since all reserve energy is settled on the short-term market. If revenue from settling the generated energy is enough to cover reserve energy's fixed revenue, there's no need to bill the charge. If it's not enough, however, billing the charge ensures the difference is covered.

Across all scenarios, the average annual PLD considered was BRL 146.36/MWh. This figure corresponds to the average of monthly medians, calculated from a historical and forward-looking PLD series spanning January 2016 through June 2026.

The charge-billing dynamic differs between captive and free consumers. For captive consumers, ANEEL considers tariff coverage equivalent to 64% of the fixed revenue for reserve energy attributed to that group. The difference between total revenue and the portion actually billed in the tariff — via the EER — is offset through the tariff-flag mechanism, and eventually via financial costs billed in the tariff. For this reason, the effects of the increase in reserve energy's fixed revenue are only partially felt by these captive consumers.

Free consumers, meanwhile, who aren't subject to tariff flags, bear the full EER. In this case, billing happens through the monthly settlement carried out by the Electric Energy Trading Chamber (CCEE), which reflects the charge calculated month by month. In the reference scenario presented, it's estimated that, in 2035, free consumers would see an average annual EER charge of BRL 15/MWh.

3.2. Scenario 1: Law No. 14,182/2021

This scenario considers implementing Law 14,182's original provisions, as approved in 2021, which are:

1. Thermal-plant contracting: We considered contracting 8,000 MW of natural-gas thermal plants with a minimum inflexibility of 70%, distributed regionally, per the original plan. However, contracting plants in the Northeast region (1,000 MW) was disregarded, since, in the first auction for such plants, held by the MME in 2022, there was no energy supply for that region. So, beyond the 670 average MW contracted for the North region, we considered the remaining future contracting, factoring in 70% inflexibility, of 4,200 average MW (1,050 average MW in the North (delivered in 2027 and 2028); 1,750 average MW in the Center-West (2028); and 1,400 average MW in the Southeast (2029 and 2030)). For contracting these 4,200 average MW, we used a price of BRL 444/MWh (referenced to Sept/22), as negotiated in the LRCE that contracted energy for the North region.
2. Hydroelectric-plant contracting: in the 37th A-5 New Energy Auction, held in 2022, 87 average MW of energy from hydroelectric plants up to 50 MW was contracted, per the market reserve defined in the law. In the 39th A-5 LEN, held on August 22, 2025, the amount contracted was 384 average MW. In terms of capacity, these two auctions together contracted 991 MW of capacity. So, in Scenario 1, beyond this completed contracting, we considered the remaining contracting of 1,009 MW, out of the 2,000 MW total, in the 2026 existing-energy A-5 auction, at the average price negotiated in that latest auction, of BRL 392.84/MWh. Since TR Soluções' projections indicate that 50% of the demand in that 2026 auction is consistent with the law's requirement, small hydroelectric plant contracting would be carried out in full. The capacity factor used in this contracting was the same seen in the A-5 auction held on August 22, 2025: 47%.

Figure 2 shows the evolution of reserve energy's fixed revenue, factoring in Law 14,182's effects on contracting the 8,000 MW of natural-gas thermal plants covered by the law. The effects of contracting small hydroelectric plants, meanwhile, are felt differently across distribution companies, since each has specific new-energy needs. Its effect, however, is felt in the projected residential consumer average tariff shown further below.

Source: TR Soluções' SETE platform.

By 2035, reserve energy's fixed revenue would reach BRL 41 billion, an increase of BRL 26 billion relative to the reference scenario. Beyond this gas-fired thermal-energy contracting in the LRCE, Scenario 1 also considered the full contracting of 2,000 MW of energy from hydroelectric plants up to 50 MW. The simulation resulted in an average tariff for Brazil's residential consumers of BRL 1,254/MWh. Relative to the reference scenario, that's an increase of BRL 81/MWh in the Brazilian residential consumer's average tariff, or an increase of 6.9%.

Free consumers, meanwhile, would see an increase of BRL 29/MWh in the EER, for a total average annual charge of BRL 44/MWh in 2035, an increase of 193%.

3.3. Scenario 2: Law No. 15,097/2025

Given the complexity and regulatory instability tied to Law 15,097's passage, with the possibility that the presidential vetoes still in place could yet be reviewed, TR Soluções' scenario assumes that all vetoes have been overridden by Congress. Under this scenario, the following contracting would be expected:

1. Thermal plants (8,000 MW): would be fully contracted, per the restored wording of §1 of Law 14,182, with the state-level redistribution set out in §§12 and 13 (Piauí, Maranhão, Amapá, and Amazonas), and with staggered delivery. The contracting model remains reserve energy with 70% inflexibility. However, beyond the remaining 4,200 average MW (factoring in inflexibility), another 700 average MW would be contracted in the North region, for which there was no supply in the first LRCE. The obligation to contract the full amount — including what wasn't contracted in previous auctions due to lack of supply — was imposed on the Executive by the legal framework. Additionally, the new provision (§6 of Article 4-A of Law 14,182) allowed the energy price to also factor in "costs related to supplying natural gas and the infrastructure needed to deliver it to the plants." Taking this condition and price references reported in the media into account, the price used was BRL 650/MWh (at Sept/22 values).
2. Hydroelectric plants (4,900 MW): we considered mandatory contracting of 4,900 MW of hydroelectric plants up to 50 MW, via reserve energy, with delivery by 12/31/2029. The pricing logic was the same as in Scenario 1, using the average price negotiated in the 39th A-5 LEN of 2025, that is, BRL 392.84/MWh (at Aug/25 values). The capacity factor used in the simulation was 47%, matching the 39th A-5 LEN of 2025.
3. Green hydrogen (250 average MW): energy from liquid hydrogen derived from ethanol in the Northeast region, with delivery by 12/31/2029. Since the commercial model to be adopted for this contracting wasn't specified, for comparison purposes TR Soluções treated this energy as reserve energy. The price used for this technology was BRL 1,560/MWh (at Jul/25 values), calculated based on information from the Energy Research Company's (EPE) Hydrogen Technology Roadmap¹
.
4. Wind power in the South (300 average MW): with delivery by 12/31/2030 and no defined contracting model, these plants were also treated as reserve energy, at the average price of the last A-5 new-energy auction (37th LEN) in which this source was contracted: BRL 176.00/MWh (referenced to Oct/22).
5. Mineral coal: we considered extending coal-plant contracts (currently in distribution companies' CCEARs) through 2050. The model and price used were the same adopted for the Jorge Lacerda Complex, that is, reserve energy at an average price of BRL 564.37/MWh (referenced to Jun/25). As a result, the source's volume now treated as reserve energy was 1,732 average MW.

Source: TR Soluções' SETE platform.

By 2035, reserve energy's fixed revenue would reach BRL 88 billion under Scenario 2, an increase of BRL 73 billion relative to the reference scenario. In tariff terms, residential consumers would see a tariff of BRL 1,291/MWh, an additional BRL 118/MWh, or 10.1%, relative to the reference scenario. The average annual charge attributed to free consumers, meanwhile, would reach BRL 97/MWh, an increase of BRL 82/MWh, or 547%.

3.4. Scenario 3: Provisional Measure No. 1,304/2025

This scenario represents MP 1,304's effects, as published:

1. Hydroelectric plants (3,000 MW): staggered contracting of up to 3,000 MW of hydroelectric plants up to 50 MW through capacity-reserve-in-the-form-of-energy auctions, with supply starting in 2032, 2033, and 2034. The price used was the average from the 2025 A-5 Auction, that is, BRL 392.84/MWh (at Aug/25 values). The capacity factor used also matched that seen in the A-5 auction held on August 22, 2025: 47%.
2. Other sources (remaining 1,900 MW of hydroelectric plants up to 50 MW, green hydrogen, and wind): not considered, given the limitations imposed by the new Article 1-A of Law 14,182, inserted by MP 1,304 itself, which conditions new contracting — except for small hydroelectric plants — on sector planning.

Source: TR Soluções' SETE platform.

Besides the hydroelectric amount already contracted in the regulated auctions (37th and 39th LEN), under Law 14,182, Scenario 3 also factors in the LRCE held in 2022. So this scenario would result in BRL 22 billion in fixed reserve-energy revenue in 2035. That's an increase of about BRL 7 billion relative to the reference scenario's figure, but a reduction of BRL 19 billion relative to Scenario 1, and BRL 66 billion relative to Scenario 2.

In practice, under Scenario 3's value, residential consumers would see an average tariff of BRL 1,184/MWh. That's an increase of BRL 11/MWh relative to the reference scenario (0.9%); a reduction of BRL 70/MWh relative to Scenario 1 (-5.6%); and a reduction of BRL 107/MWh relative to Scenario 2 (-8.3%).

Free consumers, in turn, would be subject to an average annual EER of BRL 22/MWh, which is BRL 7/MWh higher than the reference scenario's; BRL 22/MWh lower than Scenario 1's; and BRL 75/MWh lower than Scenario 2's.

3.5. Summary of the Simulated Scenarios

Beyond the reference scenario — in which no not-yet-completed energy contracting tied to the legal provisions discussed in this article was factored in, and which served as the basis for the simulations — three distinct scenarios were analyzed:

• Scenario 1 – Simulates contracting the thermal plants provided for in Law No. 14,182 through the reserve-energy mechanism, as originally envisioned, disregarding contracting in the North region, for which there was no energy supply. It also considers the additional contracting of 1,009 MW of hydroelectric plants up to 50 MW, since 991 MW had already been contracted in the 37th and 39th LEN.
• Scenario 2 – Considers Congress fully overriding the vetoes to Law No. 15,097, with mandatory contracting of the 8,000 MW of gas-fired thermal plants at a price that includes transport-infrastructure costs, and an increase to 4,900 MW in hydroelectric-plant contracting, plus 250 average MW of hydrogen from ethanol in the Northeast, 300 average MW of wind energy in the South region, and 1,732 average MW of coal-fired plants whose regulated contracts end by 2028. The contracting model considered for all this energy was reserve energy.
• Scenario 3 – Considers contracting only 3,000 MW of small hydroelectric plants for delivery in 2032, 2033, and 2034, as reserve energy. No other future contracting was considered, given the limitations imposed by MP 1,304.

The table below summarizes the main scenarios identified by the study.

Source: TR Soluções' SETE platform.

4. Final Considerations

The simulations TR Soluções ran for this study were carried out based on the best possible understanding of the information available at the time of analysis, in light of the legal provisions in force — including presidential vetoes already overridden by Congress. The scenarios considered conditionally reflect different regulatory frameworks: each was built consistent with the legislation in force during the corresponding period. This allowed us to comparatively assess tariff outcomes had the original provisions of Law 14,182 prevailed, the requirements introduced by Law 15,097 (with the presidential vetoes removed), or the changes proposed by MP 1,304.

It's important to stress the uncertainties of this moment: the conditions detailed here are subject to change based on MP 1,304's progress and any amendments to it, as well as the validity of the provisional measure itself. Under constitutional timelines, MP 1,304 is initially in force for 60 days, extendable once for an equal period, meaning it will need to be approved by Congress by early November 2025 to be converted into law. Otherwise, it will lose effect, likely restoring the previously applicable requirements. Additionally, there are still legal provisions pending definition or subject to vetoes not yet reviewed — for example, sections of Law 15,097 whose presidential vetoes haven't been voted on by Congress, which remain legally inapplicable. This volatile context means the impacts estimated here could change due to future legislative developments, requiring ongoing monitoring.

Finally, it's worth noting — as a caveat — that this analysis's conclusions shouldn't be interpreted as a deterministic forecast or as a value judgment about the legal provisions examined. This is a technical, objective, and conditional exercise, aimed at illustrating the possible tariff effects under different regulatory scenarios and energy prices by source, plus short-term prices based on a historical and forward-looking statistical metric. The projections presented are strictly tied to the legal and regulatory assumptions in force under each scenario analyzed, without any intent to anticipate future legislative or regulatory decisions. In other words, the results shown stem from the specific combinations of mandatory-contracting requirements in force under each hypothetical context, serving as an informational reference for understanding potential impacts under different legal trajectories.

It's worth stressing that TR Soluções' estimates reflect each scenario's legal context and don't represent a guarantee of occurrence or an assessment of the merits of the regulatory instruments in question. In a dynamic regulatory environment like the one we're seeing, it's important that these results be understood solely in light of the conditions set out in each scenario considered.

* TR Soluções Regulatory Team.

¹ EPE/DEA/SEE/014/2025 Technical Note.