December 3, 2025

Law No. 15,269/2025 (Power Sector Reform): Will There Be Tariff Moderation?

Summary

Law No. 15,269/2025 could deliver an average reduction of 7% in tariffs for residential energy consumers over the next 12 years. This reduction is associated with a drop of about 11% in the Electricity Tariff (TE) and 4% in the wire-usage tariff (TUSD). These findings are part of an analysis of the tariff effects of nine elements changed by the new legislation with a direct, measurable impact on the makeup of amounts charged to electricity consumers across Brazil, such as the creation of the Supplementary Resources Charge (ECR), the new CDE GD allocation criterion, and the end of the incentivized-energy discount for new free consumers. To do this, two average tariff trajectories were estimated for residential consumer units using the Energy Tariff Estimation Service (SETE), by TR Soluções: Scenario I disregards the application of the new legislation, while Scenario II incorporates the changes.

1. Introduction

Law No. 15,269/2025 (Law 15,269), published on November 24, 2025, resulting from Provisional Measure No. 1,304/2025, brings structural changes to the legal framework of the Brazilian power sector. Its goals include tariff moderation, modernization of the regulatory framework, strengthening energy security, setting guidelines for regulating electricity storage, creating economic incentives for battery systems, and adopting mechanisms to facilitate the sale of natural gas owned by the Federal Government.

Since MP 1,304/2025 was issued and approved by Congress as Conversion Bill No. 10/2025 (PLV 10/2025), TR Soluções has been working on updating its tariff-projection and market-intelligence model — the Energy Tariff Estimation Service (SETE) — so it incorporates the new legislation's provisions in a technical, prudent way.

This article analyzes the tariff effects of nine elements with a direct, measurable impact on the makeup of amounts charged to electricity consumers across Brazil:

1. creation of the Supplementary Resources Charge (ECR);
2. new CDE GD allocation criterion;
3. end of the incentivized-energy discount for new free consumers;
4. new criterion for allocating CDE Usage across voltage levels (HV, MV, and LV), starting in 2026;
5. end of the quota regime for generation concessions with upcoming expirations;
6. contracting of the Candiota III coal-fired thermal plant as reserve energy;
7. opening the market to low-voltage consumers;
8. funding of retroactive liabilities for generation cuts (curtailment);
9. contracting 3 GW of hydroelectric plants up to 50 MW as reserve energy.

To quantify the potential tariff impact of these legal provisions, two average tariff trajectories were estimated for residential consumer units, over a 12-year horizon. Scenario I disregards the application of the new legislation, while Scenario II incorporates the changes. The results are shown in the chart below.

Source: TR Soluções, SETE platform.

In summary, the provisions analyzed affect free and captive consumers differently. Estimates point to, for the residential B1 class, a Brazil-average reduction of 7% in the Application Tariff over 12 years, resulting from a drop of about 4% in the Distribution System Usage Tariff (TUSD) and 11% in the Electricity Tariff (TE) over the same horizon. In contrast, consumers who buy incentivized-source energy will now bear the new Supplementary Resources Charge.

Source: TR Soluções, SETE platform.

In the short term, the TUSD is affected by the establishment of the CDE cap. Effects on the TE, meanwhile, are felt in the medium and long term, resulting not only from the new CDE GD allocation and the end of the quota regime, but fundamentally from the change in assumptions for reserve-energy contracting. Unlike the previous projection (Scenario I), which incorporated the mandatory contracting of 8,000 MW of inflexible natural-gas thermal plants (Law No. 14,182/2021) — whose impacts were detailed by TR Soluções in the article The Tariff Weight of Planning Shortcuts —, the current base scenario (Scenario II) reflects Law 15,269's new guideline, excluding that requirement. This change removes significant pressure on the future Reserve Energy Charge (EER), contributing decisively to the observed reduction in the TE, despite the remaining uncertainty over Congress's review of vetoes.

Source: TR Soluções, SETE platform.

For the projections presented¹, TR Soluções factored in interpretations of measures that still depend on regulation by the Ministry of Mines and Energy (MME), the National Electric Energy Agency (ANEEL), and any decisions Congress may make regarding presidential vetoes.

2. Energy Development Account (CDE)

The CDE — through its CDE Usage, CDE GD, and CDE Eletrobras components — was, without doubt, the star of the new legal framework, especially regarding tariff-moderation tools.

Among the nine topics analyzed in this article, six directly affect the projected trajectory of the CDE: 1) ECR; 2) CDE GD as a CDE expense; 3) end of the incentivized-energy discount; 4) new criterion for allocating CDE Usage among HV, MV, and LV; 5) end of the Quota regime; and 6) contracting of the Candiota III coal-fired thermal plant.

Source: TR Soluções, SETE platform.

2.1 Supplementary Resources Charge (ECR)

Comparing the two scenarios shows that applying the legal cap on the CDE creates progressive constraints on the charge's budget. In the cap's first year in force, 2027, these constraints already add up to about BRL 2 billion (Figure 5).

To address constraints of this kind, Article 7 of Law 15,269 creates the Supplementary Resources Charge (ECR). This new funding source for the CDE is described in item XI added to §1 of Article 13 of Law No. 10,438/2002 (Law 10,438):

11. "from the Supplementary Resources Charge to fund the expenses defined in item I of §20 of this article."

§20 complements this by defining that the ECR:

1. "will be used to cover the difference between the budgeted amount and the limit referred to in item II of §18 for the corresponding expense item;" (our emphasis)

This is one of the most structural and sensitive elements of Law 15,269, since it replaces the natural expansion of certain tariff benefits with an annual expense cap, with a direct impact on tariff moderation.

• Calculation method in SETE

To calculate the ECR, we assumed that, starting in 2027, each benefit's charge corresponds to the difference between:

1. the expense cap value in the CDE's 2025 Annual Budget, adjusted by the IPCA; and
2. that expense's actual value in the CDE budget for the year analyzed.

So the ECR would work as an individual cap for each benefit explaining CDE expenses.

The simulation disregards certain CDE expenses excluded from the ECR. These are (Article 13 of Law 10,438):

For the CDE's other expenses, the ECR will be applied individually. Each benefit making up CDE expenses will have its own ECR, calculated as the difference between the cap and the expense's actual value. TR Soluções' projections indicate that, within the horizon considered, two CDE expense items would hit the cap, resulting in corresponding ECR charges. They are: Incentivized-Source Consumer and Transmission Discounts.

Source: TR Soluções, SETE platform.

Figure 5 presents the annual ECR projections by expense type for 2027. The figures represent, for each expense item, the amount needed to bring the expense back to its legal cap. This dynamic allows the ECR-specific tariff per expense type to be derived transparently, linking the annual economic amount to the energy tied to that incentive.

Source: TR Soluções, SETE platform.

Figure 6 compares the annual ECR volumes to the size of the respective expenses for 2027. The ratio between these two figures will determine, for each year, the percentage reduction in the tariff benefit associated with triggering the cap.

Source: TR Soluções, SETE platform.

Figure 7 presents, also for 2027, the estimated ECR Tariffs. The figures represent the ratio between the Individual ECR shown in Figure 5 and the energy volumes tied to the benefit explaining the corresponding CDE expenses. This makes it possible to quantify, on an annualized basis, the intensity of the reduction imposed by Law 15,269 on each CDE expense subject to the mechanism.

2.2 New CDE GD Allocation Criterion

Law 15,269 brought a structural change to how subsidies for Micro and Mini Distributed Generation (MMGD) are funded. The most immediate and unambiguous change is broadening the allocation base to include all consumers in the National Interconnected System (SIN). Previously, the cost was passed on only to regulated consumers.

This guideline was set out through two changes to Law No. 14,300/2022 (Law 14,300):

1. Amendment to Article 25: Article 14 of the new law removed from the original text the phrase restricting CDE GD allocation "only to consumer units in the regulated environment."
2. Repeal in Article 22: Article 23 of the new law repealed the sole paragraph of Article 22, which also shielded the free market from DG allocation in permission-holder and small distribution-company areas.

In practice, these provisions shift the CDE GD subsidy, today embedded in the TE and paid exclusively by captive consumers, to the TUSD cost structure, also reaching free consumers.

But there are doubts about how CDE GD fits into the ECR, which depends on regulatory interpretation. The final text as signed vetoed the creation of item XIX in Article 13 of Law 10,438, which would have created a specific line item for DG under the new charge. At first glance, this could suggest excluding the expense from the cap. However, the new wording of Article 25 of Law 14,300 states that the CDE will fund DG "in accordance with Article 13, caput, items VI and VII, of Law No. 10,438".

Since items VI (incentivized sources) and VII (TUSD discounts) aren't listed among the exceptions to the cap (listed in §18, item I), a strictly literal interpretation of the law would lead to the conclusion that CDE GD is part of the CDE's capped expense base.

Despite this possible interpretation — which would tie CDE GD to the cap via items VI and VII —, this study chose not to consider it subject to the ECR.

If CDE GD were also subjected to the cap, the projected volume of this expense could trigger the ECR as early as the cap's first year in force (2027), imposing a 27% reduction in the tariff benefit associated with triggering the cap.

2.3 End of Incentivized-Energy Discounts

With the new law taking effect, discounts on the wire tariff (TUSD/TUST) for incentivized energy tied to new migrations to the Free Contracting Environment (ACL) come to an end. In other words, consumers who join the free market after the law's publication will no longer be able to sign contracts providing for discounts on distribution or transmission system usage tariffs for purchasing energy from incentivized sources. This is the end of the possibility for new free consumers to enjoy this tariff benefit, ensuring that new entrants bear the full wire charges.

On the other hand, as a SETE (TR Soluções) assumption, existing contracts are maintained. Free consumers who, before the new law, signed contracts to buy incentivized energy with discounts on usage tariffs will continue to enjoy that advantage. These contracts remain valid under their original terms. Operational details and prohibitions aren't yet known.

The cost of these discounts will continue to be covered by the CDE Usage. So, at first, there's understood to be no actual loss for current beneficiaries, with contractual stability preserved.

However, the law introduces a new instrument for controlling maintained benefits: linking these contracts to the ECR. This means beneficiaries now have an individual subsidy cap, calculated from the amount budgeted in the CDE in 2025, adjusted by the IPCA. As a result, they'll have to return part of the discounts through the new charge. In practice, then, they should keep enjoying the discount until the cost associated with the ECR approaches or exceeds the tariff benefit itself. From that break-even point on, the economic incentive disappears.

It's also worth noting that the subsidy's evolution should directly track the expected growth of the Fio A (transmission) and Fio B (distribution) tariff components, since the discount is applied to those portions of the tariffs.

TR Soluções expects these costs to grow faster than the IPCA, which implies a proportional increase in the nominal value of the benefit granted per unit of energy. As a result, consumers with existing contracts tend to hit their individual ECR caps sooner, speeding up the loss of the economic incentive and, in practice, bringing forward the drop in incentivized energy's attractiveness.

2.4 CDE Usage Allocation Among HV, MV, and LV

Before Law No. 13,203/2015 (Law 13,203), allocation of the CDE Usage sectoral charge followed the "postage-stamp" criterion — that is, each consumer unit contributed proportionally to its energy consumption, with differentiation only between subsystems: consumers in the South and Southeast/Center-West were subject to a CDE Usage tariff 4.5 times higher than those in the North and Northeast subsystems. This regional distinction was maintained even after the latter two were fully interconnected to the SIN, perpetuating tariff asymmetry in how the main sectoral charge is allocated between regions.

Source: ANEEL, PRORET Sub-module 7.2 .

Law 13,203 set two important transitions in this model starting in 2017: the first, between subsystems, aiming to gradually standardize the CDE Usage charge across Brazil by 2030 (a transition kept in place by Law 15,269); the second, between supply voltage levels, so that starting in 2030 high-voltage (HV) consumers would pay 33% of the tariff set for low-voltage (LV) consumers, and medium-voltage (MV) consumers would be subject to a CDE Usage tariff equivalent to 67% of the tariff set for LV consumers.

Provisional Measure No. 1,300/2025 had even proposed repealing this differentiation by voltage level — reinstating "postage-stamp" allocation starting in 2038 —, but that proposal was dropped when the MP was converted into Law No. 15,235/2025. However, Law 15,269 redefined the transition trajectory set out in Law 13,203, fixing, starting in 2026, new allocation factors, namely 50% for HV relative to LV; and 80% for MV relative to LV. This move effectively keeps the current CDE Usage allocation constant across voltage levels starting in 2026, halting the previous transition.

2.5 End of the Quota Regime

Quota energy, from Firm Capacity Quota Contracts (CCGF), is the regime under which firm energy and capacity capacity from hydroelectric plants with concessions extended under Law No. 12,783/2013 and re-bid under Law 13,203 is compulsorily allocated among SIN distribution companies. This allocation is set in advance, with costs, burdens, and benefits from the variation between actual generation and firm energy allocated to the group of quota holders, passed directly on to captive consumers' tariffs.

Source: TR Soluções, SETE platform.

SETE, in its previous version (Figure 9), assumed that energy from generation concessions would continue to be renewed under this quota regime, under the terms of Law 13,203. With the publication of Law 15,269, however, that arrangement, projected in the figure below, is now replaced.

The new model provides for paid extension or re-bidding of concessions for hydroelectric plants (UHEs) above 50 MW granted before 12/11/2003, through adoption of the independent power producer (PIE) regime, with a concession term of 30 years. These plants will have their firm energy recalculated, with no floor on the reduction, and will fully assume hydrological risk. Half of the grant revenue will go to tariff moderation as CDE revenue, and half to the Federal Government.

Energy generated by renewed or re-bid plants may be sold either in the Regulated Contracting Environment (ACR) or in the ACL, with the Executive Branch allowed to set a minimum percentage to be contracted by ACR distribution companies. Additionally, the 50% grant share will be mandatorily allocated to the CDE for concessions expiring by 12/31/2032.

If a UHE concession isn't renewed, whether due to the concession holder's lack of interest or a decision by the granting authority, the project will be auctioned under the new PIE regime, with the winner paying a grant fee and assuming hydrological risk.

Ending the quota regime has a direct impact on distribution companies' contract portfolio, which today includes about 13% quota energy, and also reduces expenses under the Tariff Flag Centralizing Account (CCRBT) tied to hydrological risk. It also creates a new revenue source for the CDE, from grant-fee collection.

Source: TR Soluções, SETE platform.

In TR Soluções' SETE, it's assumed that, starting in 2026, generation plants with expiring concessions will no longer renew them under the quota regime, and those already operating under this model will exit it as soon as their contracts end. In addition, the projections factor in CDE revenue equivalent to 50% of the grant value, calculated using the New Replacement Value (VNR) methodology — similar to that applied in Eletrobras' privatization — and spread evenly over the new concession's 30 years.

2.6 Coal-Fired Power Plant Contracts

Historically, the CDE housed the "Mineral Coal Subaccount," created by Law No. 10,438/2002. This public policy's goal was to ensure the competitiveness of domestic coal-fired thermal generation against other sources, through reimbursement of up to 100% of fuel costs, capped at minimum contractual purchase volumes. Under the legislation in force before Law 15,269 (specifically Law No. 12,783/2013), this direct CDE subsidy had a set expiration date: the year 2027.

Source: Electric Energy Trading Chamber (CCEE), 2025 Sector Accounts Budget Assumptions.

The benefit was historically concentrated in three ventures, whose recent trajectories diverge significantly:

1. Jorge Lacerda Thermal Complex (SC): with 857 MW of installed capacity and owned by Diamante Geração de Energia, it was the largest historical beneficiary (accounting for about 85% to 90% of transfers). Under Law No. 14,299/2022, its contracts were converted into Reserve Energy Contracts (CER), removing the cost from the CDE subsidy (the "Mineral Coal" line item) and transferring it to the Reserve Energy Charge (EER).
2. Figueira Plant (PR): this small plant (20 MW) also received CDE subsidies. It's currently suspended and in the process of returning its grant to Copel Geração (ANEEL Order No. 561/2024). However, if operations resumed, it could fall under the new legal guidelines.
3. Candiota III Plant (RS): Operated by Âmbar Energia with 350 MW of installed capacity, it's the central focus of the changes brought by Law 15,269. Its Regulated Environment Trading Contracts (CCEAR) expired on December 31, 2024. Since January 2025, the plant has been operating without a contracted sales backstop (acting as a merchant plant or under inflexibility dispatch), but retains the right to fuel reimbursement from the CDE up to the 2027 legal limit.

Law 15,269 structurally changes support for the Candiota III plant (and potentially for the Figueira plant, if reactivated). The new legal provision determines that these plants be contracted as capacity reserve. However, TR Soluções interprets this guideline in the SETE model as contracting capacity reserve in the form of energy (that is, Reserve Energy), along the same lines applied to Jorge Lacerda. This assumes the operation's continuation and a guaranteed fixed revenue funded by the EER through 2040. Contracting 3 GW of hydroelectric plants as reserve energy explores this contracting format adopted in SETE in greater detail.

This shift to the EER should generate an additional specific cost for consumers. In SETE's simulations, we considered contracting an amount of 228 average MW at a price of BRL 566/MWh (in October 2019 values). Assuming an average annual Settlement Price of Differences (PLD) of BRL 151/MWh, this arrangement is estimated to result in an additional impact of BRL 2.30/MWh on the EER tariff in 2027, the year the model assumes the new contract is fully in force.

3. Opening the Market to LV Consumers

With Law 15,269 enacted, TR Soluções' tariff projections now adopt, as a base scenario, the actual opening of the Low-Voltage (LV) market starting January 1, 2028².

As noted above, the new legislation bars new migrations to the ACL from enjoying TUSD discounts tied to incentivized energy. As a result, LV migration starting in January 2028 will affect distribution companies' prospective energy balance (reducing the captive market), but will not change the CDE's annual budget figures, since these new free consumers won't bring wire-tariff subsidies with them.

Source: TR Soluções, SETE platform.

To size the LV migration scenario, we assumed Brazil has about 75 million consumer units (CU) at low voltage, excluding the low-income subclass, and that the potential market for migration corresponds to 30% of that total, or approximately 22 million CUs, each with average monthly consumption of 235 kWh.

Regarding the speed of this migration, we assumed that Group B uptake will follow a diffusion curve similar to that historically observed in Group A migrations, specifically migrations by MV consumers. So we project that, once the market opens, the initial pace will be 10,000 migrations per month across the country — representing a volume of about 2 GWh/month, equivalent to 0.03% of the total eligible low-voltage market.

4. Costs from "Curtailment" Under the ESS

Law 15,269 established retroactive compensation, starting September 1, 2023, for solar and wind plants for generation cuts due to transmission-grid failures (reliability), provided that generators who filed lawsuits withdraw them.

Source: TR Soluções, SETE platform.

Based on reliability-curtailment data made available by the ONS (Dynamic Generation Restriction Tracking), TR Soluções estimates the impact on generators of retroactive compensation at about BRL 3.8 billion. If that amount were paid off in a single month, it would add BRL 84.00/MWh to tariffs for all consumers³.

Looking ahead, in a scenario where the reliability curtailment observed over the last 12 months repeated in coming years, annual figures for this new charge would be expected on the order of BRL 3.3 billion. In tariff terms, that's equivalent to an increase of about BRL 5.14/MWh throughout the year.

Source: TR Soluções, SETE platform.

Considering only reliability-related cuts being compensated, we project an average tariff of BRL 4.13/MWh in 2027. For this estimate, we assumed an average annual PLD of BRL 151/MWh.

5. Contracting 3 GW of Hydroelectric Plants as Reserve Energy

The new law establishes mandatory contracting of 3 GW of hydroelectric plants up to 50 MW as reserve energy, with a 25-year supply term, as well as contracting the Candiota III thermal plant under the same terms through 2040, as detailed in section 2.6.

Funding this type of generation falls on consumers through the Reserve Energy Charge (EER). This charge's value is dynamic and depends directly on the PLD, since all energy generated under this modality is settled on the short-term market. The mechanism works as a compensation: if revenue from settling the energy exceeds the plants' contractual fixed revenue, no charge is billed; otherwise, the EER is triggered to cover the difference.

Currently, the fixed revenue to be covered by the system consists of a heterogeneous portfolio of contracts:

• LER (Reserve Energy Auctions): contracts from ordinary reserve-energy auctions held through September 2016;
• PCS (Simplified Competitive Procedure), the "emergency auction" from the 2021 water crisis: although scheduled to end in 2025, an agreement between ANEEL, MME, and the Federal Court of Accounts (TCU) allowed part of this supply to be extended through 2032;
• MP No. 1,232/2024: conversion of Amazonas Energia's natural-gas thermal contracts into reserve energy;
• LRCE (Capacity Reserve Auction in the form of Energy): held in 2022, contracted 670 average MW in the North region; and
• Law No. 14,299/2022: contracting of the Jorge Lacerda Thermal Complex (CTJL).

For the 12-year horizon of the tariff projections, TR Soluções incorporated new future contracting and recent legal definitions into SETE's base scenario:

• Hydroelectric plants up to 50 MW: In compliance with Law 15,269, we considered mandatory contracting of 3,000 MW of small hydro plants, although such contracting could reach 4,900 MW, with a 25-year supply term.
• Candiota III Plant: Also due to the new legislation, we projected the plant's contracting as reserve energy through 2040, detailed in section 2.6.

To quantify the specific effect of the legal requirement for hydroelectric plants up to 50 MW, the model considered full contracting of the mandatory 3,000 MW, adopting a 47% capacity factor, a level consistent with that seen in the most recent new-energy auction for that source. The reference price used was BRL 383/MWh (at March 2027 prices, the date TR Soluções assumed for the auction).

It's worth noting that the monetary-adjustment rule strictly follows the new legislation: as set out in Article 13 of Law 15,269, amending §1 of Article 1 of Law 14,182, this price cap must be updated by the INCC until the bidding notice's publication date and, after the auction, adjusted by the IPCA. Based on these assumptions and the same average PLD of BRL 151/MWh, we project an additional EER impact of BRL 5.80/MWh in 2035, once the 3,000 MW are fully contracted.

A sensitive point in the modeling concerns the nature of the new contracting (hydroelectric plants up to 50 MW and Candiota III). In both cases, there's still some confusion, and even uncertainty, over the final contracting format for these plants. Although Law 15,269's text refers to contracting as "capacity reserve," that is, contracting to meet 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, adopted as an assumption in SETE, is that the costs of this contracting should be borne by consumers via the EER, as happens in the traditional reserve-energy model tied to inflexibility.

Another important point relates to not factoring in the contracting of 3,000 MW of biomass thermal plants provided for in §15-A of Article 1 of Law 14,182, added by Law 15,269, since the legal text itself makes this contracting conditional "on the need identified by sector planning, based on technical and economic criteria set by the National Energy Policy Council – CNPE." Given this conditionality, TR Soluções chose not to incorporate these volumes into the base scenario, assuming that these systemic-need criteria will prevail. The same logic applies to the additional 1,900 MW of hydroelectric plants.

Finally, there's a relevant risk factor on the horizon: contracting 8,000 MW of natural-gas thermal plants, originally provided for in Law 14,182 and reintroduced during the passage of the offshore wind framework (Law No. 15,097/2025). Although this provision was vetoed when Law 15,097 was signed, there's still a chance Congress could override the veto. If that happens, there would be a significant increase in reserve-energy fixed revenue and a greater need for renewable-generation cuts, doubly pressuring the EER and ESS sectoral charges.

6. Final Considerations

This study served a dual purpose: to guide SETE users on the structural updates implemented in version 15.0 of the platform, and, at the same time, to offer the market a quantitative estimate of the potential tariff impacts arising from Law 15,269.

Analyzing the nine vectors of change — ranging from the new CDE cap to mandatory Reserve Energy contracting — shows that the Brazilian power sector is entering a regime transition. In the case of the CDE, in particular, we're moving from a model of automatic cost pass-through to a scenario of budgets limited by the Supplementary Resources Charge (ECR) and the reallocation of subsidies between free and captive consumers.

However, it's essential to stress that the projections presented in this article, including the estimated BRL 2 billion impact from CDE constraints already in the cap's first year in force and the new curtailment charges, aren't definitive verdicts. They're the result of technical assumptions adopted by TR Soluções to translate complex, sometimes ambiguous, legal provisions into tariff algorithms.

Whether these figures materialize invariably depends on the regulator's "pen." After all, although Congress designs the legal architecture and the Ministry of Mines and Energy sets policy, there's an institutional understanding that the sole tariff authority in Brazil is ANEEL. It will be up to the Agency to have the final word on the fine-grained regulation of sensitive topics, such as applying the cap to CDE GD or the exact contracting format for capacity reserve.

So, Scenario II outlined here should be interpreted as a prudent analytical reference, not an absolute truth. As regulation advances and Law 15,269's gaps are filled, TR Soluções will revisit its assumptions, ensuring that SETE stays aligned with regulatory reality and continues serving as a reliable compass for decision-making by power-sector agents.

¹ The updates made to SETE — released in version 15.0, on 12/03/2025 — already incorporate these interpretations, and serve as an analytical reference for assessing their potential tariff effects.

² The feature for simulating the ACL opening for LV consumers has been part of the SETE platform since November 2022 (version 14.48).

³ A feature was added to SETE to simulate the curtailment financial liability and the timing of its billing in ESS form, along with a tool to track and project the energy volume associated with generation cuts, as well as the corresponding tariffs tied to the charge.

* TR Soluções Regulatory Team.