August 13, 2026
PL 5.017/2019: impacts of mandatory procurement on electricity tariffs
Summary
The substitute bill to PL 5.017/2019 approved by the Senate's Infrastructure Services Committee introduces new obligations for procurement of natural gas-fired thermal generation and hydroelectric plants of up to 50 MW. This article analyzes the main provisions of the proposal and estimates their potential effects on the power sector's costs and consumer electricity tariffs. Simulations conducted by TR Soluções indicate that, should the procurements be implemented under the evaluated conditions, the revenue associated with Reserve Energy could experience significant increases beginning in the next decade, reaching an estimated tariff impact of 5% on B1 Residential subgroup tariffs in 2036. The results underscore the importance of supply expansion decisions being aligned with needs identified by sectoral planning and competitive procurement mechanisms.
1. Introduction
Since 2021, with the enactment of Law nº 14.182/2021 (Law 14.182), TR Soluções has been monitoring the recurrence of legislative initiatives establishing specific obligations for electricity generation procurement, often with predetermined definitions of source, location, and operational characteristics. Throughout this period, the company has conducted simulations to assess the tariff impacts of these measures, particularly when procurements do not stem from needs identified by sectoral planning and traditional competitive mechanisms. The substitute bill approved by the Senate's Infrastructure Services Committee (CI) for Bill nº 5.017/2019 (PL 5.017) reframes this debate at the center of discussions on sectoral governance and electricity tariff affordability.
Conceived in the Chamber of Deputies to address exclusively tariff aspects applicable to irrigation, aquaculture, and human water supply via artesian wells, the text incorporated structural supply expansion issues in the Senate—specific provisions for the procurement of natural gas-fired thermal plants and hydroelectric plants of up to 50 MW—as well as adjustments to the Energy Reallocation Mechanism (MRE) and innovation and research guidelines at the National Electric Energy Agency (Aneel).
From the perspective of supply and allocation of sectoral costs, the text establishes three mandatory procurement blocks:
- Natural gas-fired thermal generation from Amazonian sources in the North region, in an amount equivalent to the difference between installed capacity and physical guarantee of structural local power plants, with operational modulation under the responsibility of the National Electric System Operator (ONS).
- Procurement of 4,900 MW in hydroelectric plants of up to 50 MW, with 25-year contracts and supply schedule between 2032 and 2035.
- 2,500 MW in gas plants with minimum inflexibility of 70%, with contracting by the first quarter of 2027 and operation start by July 2032.
In all fronts, the resulting costs are shared among users of the Integrated National System (SIN), except those in the low-income residential subclass.
The imposition, by law, of specific generation expansion blocks is part of a movement observed in the power sector in recent years, with Law 14.182, the offshore wind generation legal framework (Law nº 15.097/2025) and, more recently, Law nº 15.269/2025 (Law 15.269).
Technical analyses of these legislative mechanisms demonstrate the importance of maintaining alignment between new generation procurement and sectoral planning. The ex-ante fixing of source, location, inflexibility level, and cost allocation restricts the space for sectoral planning and competitive mechanisms to define lowest-cost expansion alternatives, pillars of efficient risk allocation in the sector and electricity tariff affordability.
Quantitative studies developed by TR Soluções confirm this premise. In previous simulations on mandatory procurement scenarios, such as in an article published in September 2025, it was identified that fixed allocation of guarantees and reserve charges tends to produce significant effects on tariffs.
In this study, which specifically analyzes the tariff impact potential of the PL 5.017 substitute, the scenario repeats: economic modeling consistently indicates that the introduction of supply obligations disconnected from technical necessity signals tends to increase systemic costs.
2. Thermal generation with Amazonian-sourced gas
The substitute provides for the conduct of specific auctions for natural gas-fired thermal generation from Amazonian sources in the North Region. The mechanism ties the procurement volume to the difference between installed capacity and physical guarantee of hydroelectric plants contracted through Structural Project Auctions (Belo Monte, Jirau, and Santo Antônio).
These hydroelectric plants were designed in the run-of-river model. The difference between nominal installed capacity (18,551 MW) and aggregate physical guarantee (9,107 MWm) reflects the seasonality and design characteristics of these ventures, not constituting, in a regulatory sense, an operational inefficiency to be corrected by thermal supply.
It is important to note that the new legal text limits procurement to 60% of the expansion need for inflexible natural gas-fired thermal generation established in the Ten-Year Energy Expansion Plan (PDE 2035), by the Energy Research Company (EPE).
The argument in favor of procuring gas thermal plants is that this thermal generation was already foreseen by official planning. This point requires a methodological caveat. The PDE 2035 reference scenario incorporates 7,246 MW of inflexible gas thermal plants because it was developed under the regulatory mandate to represent the legal requirement of Law 14.182. However, when EPE performs simulations decoupled from these mandatory procurements—as demonstrated in the sensitivity analysis to Law 15.269 presented in the PDE 2035 itself—the lowest-cost total expansion trajectory does not include new inflexible thermal plants by 2035, as they prove uncompetitive from a technical-economic standpoint.
It is therefore incumbent on the legislator to clarify whether the 60% limit applies to the PDE 2035 reference trajectory (tied to the history of Law 14.182) or strictly to the need identified by planning models without legal imposition.
In this study, the 60% was assumed to apply to the inflexible expansion of the PDE 2035 reference scenario (7,246 MW), so that the resulting maximum volume would be 4,348 MW.
For measuring the economic and tariff impact of this procurement, a reference value of BRL 800/MWh was adopted for simulation purposes as the average total cost of delivered energy (fuel, capital, and operations). This assumption is based on concrete sector benchmarks:
- History of auctions in isolated/Amazonian systems: in the Roraima Supply Auction (2019), which enabled UTE Jaguatirica II from gas in the Azulão field (AM), the average price was BRL 833/MWh.
- Cost Parameters in PDE 2035: the unit variable cost (CVU) of flexible gas thermal plants estimated by EPE reaches BRL 1,000/MWh, while inflexible plants present CVUs between BRL 430/MWh and BRL 490/MWh, to which must be added fixed investment and transport logistics costs.
A potential procurement of 4,348 MW at the reference price of BRL 800/MWh, with inflexibility of 51%1 (complement of the capacity factor of structural hydroelectric plants), would result in approximately 19.4 TWh/year of inflexible generation, corresponding to a cost of approximately BRL 15.5 billion per year.
3. Procurement of hydroelectric plants of up to 50 MW
The substitute text establishes the obligation to procure a total amount of 4,900 MW in small hydroelectric plants, determining that the auction for procurement be conducted by the Executive Power within up to 12 months from the publication of the new law (exceeding the first quarter 2026 deadline under current legislation, which provides for mandatory procurement of 3,000 MW of the source). The supply start schedule, in 25-year contracts, becomes distributed on the following scale: 2,000 MW with supply start in 2032; 1,000 MW in 2033; 1,000 MW in 2034; and 900 MW in 2035.
In parallel, the project alters the monetary update rule for the reference ceiling price. While current rules provide for full correction by the Construction Cost Index (INCC) in the pre-auction phase, the new text introduces a hybrid indexer composed of 50% INCC and 50% Agricultural Price Index (IPA) in the period preceding the auction, maintaining full Broad Consumer Price Index (IPCA) adjustment for contract resets during the supply phase.
Taking as initial reference the price of BRL 392.84/MWh verified in the August 2025 A-5 Auction, corresponding to the update of the reference price for hydroelectric plants from the 2019 A-6 Auction, and applying, approximately, the hybrid update proposed through August 2027, the date adopted by TR as the premise for conducting the auction, the starting price is estimated at BRL 429.00/MWh.
Full procurement of the 4,900 MW at this reference value, under a capacity factor of 47% (equivalent to that observed in recent auctions of the source), results in a volume of mandatory generation of 20.2 TWh/year when all blocks are in commercial operation (from 2036 onwards). This corresponds to a total fixed revenue of approximately BRL 8.7 billion per year (at August 2026 prices).
The final effect passed on to electricity bills through a charge will depend on the Short-Term Market Price (PLD), since the dynamics of this procurement is assumed to be that of reserve energy. It should be noted, however, that this estimate considers only the fixed revenue associated with generation procurement. Other economic effects provided for in the substitute have not been quantified at this stage, particularly the costs associated with hydrological risk (GSF) assumed by SIN users, whose magnitude will depend on hydrological conditions and future regulations.
4. Natural gas-fired thermal generation with 70% inflexibility
The second thermal front introduced by the PL 5.017 substitute establishes mandatory procurement of 2,500 MW in new natural gas-fired plants with minimum annual inflexibility of 70%, for a supply period of 15 years. This results in a minimum mandatory generation volume of 15.33 TWh/year.
The proposal sets the procurement deadline by the first quarter of 2027 and supply start by July 2032, with mandatory regional distribution among Goiás, Integrated Development Region of the Federal District and Surroundings (RIDE-DF), Rondônia, Triângulo Mineiro, and Metropolitan Region of São Luís.
The absence of gas transport infrastructure in these regions requires the construction of new pipelines (with thermal plants acting as demand anchors for pipeline networks) or the structuring of LNG/CNG chains (virtual pipeline), solutions that add high infrastructure or freight costs to the final fuel price.
Furthermore, the fixing of a 70% inflexibility floor imposes a high minimum level of thermal generation throughout the year. In a scenario marked by accelerated expansion of variable renewable sources (solar and wind) and periods of daytime oversupply, the mandatory continuous thermal generation reduces the accommodation space for renewable energy in the market, potentially intensifying generation curtailment episodes and raising the overall cost of SIN operation.
The relevance of the 70% minimum inflexibility imposition should also be analyzed in light of the current composition of SIN thermal generation. The system already presents a significant share of thermal generation associated with inflexibility, reducing the available space for this fleet to respond to economic signals and system operational needs.
Figure 1 illustrates thermal generation by dispatch reason, on a daily basis, between January 1, 2021, and July 9, 2026. During this period, inflexible generation averaged 4,176 MWm, corresponding to 56% of total thermal generation of 7,393 MWm. When disregarding 2021 and 2022, marked by hydrological scarcity and elevated thermal dispatch for other reasons, this share increases: between January 2023 and July 2026, average inflexible generation was 4,279 MWm, equivalent to 67% of total thermal generation.
The data thus shows that the introduction of new thermal blocks with high inflexibility would occur in a system where a relevant share of thermal generation already operates with low responsiveness to economic dispatch signals. In periods of high renewable generation availability, the expansion of this share may reduce SIN operational flexibility and increase the need for generation cuts from other sources.
Figure 1 – SIN thermal generation by dispatch reason, in MWm, between 01/01/2021 and 09/07/2026
Source: TR Soluções' SETE platform, based on ONS data.
For evaluating economic impacts, a reference average price of BRL 750.00/MWh at today's values was adopted as an estimate. This price is based on PDE 2035 parameters, considering fixed O&M, taxes, investment amortization, and logistics. Thus, the fixed annual revenue to meet this procurement would be approximately BRL 11.5 billion.
5. Potential tariff impacts from mandatory procurement provided for in PL 5.017
To measure the potential effect of the PL 5.017 substitute on electricity bills, TR Soluções modeled two reserve energy fixed revenue trajectories on the SETE platform. The quantitative analysis developed in this section is restricted to effects associated with the three generation procurement blocks described in sections 2 to 4. Other provisions introduced by the substitute have not been quantified. Likewise, the prices adopted for new procurements constitute references for simulation purposes and do not represent estimates of prices that will actually result from future auctions. These values may vary depending on, among other factors, financing conditions, fuel and logistics costs, level of competition, project configuration, and conditions established in auction notices. The following scenarios were simulated:
- Base Scenario (without PL): consolidates existing and already-contracted power sector commitments, including Reserve Energy Auctions (LER), Simplified Competitive Procedures (PCS), Capacity Reserve Auction in Energy Form (LRCE), the Jorge Lacerda Thermal Complex (CTJL - Law nº 14.299/2022), Provisional Measure nº 1.232/2024, and the addition of UTE Candiota III, as provided by Law 15.269. It is important to highlight that this reference scenario disregards the mandatory procurement of 3,000 MW in hydroelectric plants of up to 50 MW originally stipulated by Laws 14.182 and 15.269.
- Scenario with PL (substitute to PL 5.017): reintroduces and expands mandatory procurement of hydroelectric plants of up to 50 MW (totaling 4,900 MW or 2,303 MWm at the base price of BRL 429.00/MWh), adds the block of 2,500 MW in inflexible thermal plants at 70% (1,750 MWm, at BRL 750/MWh), and incorporates Amazonian gas generation (approx. 4,348 MW or 2,217 MWm, with 51% inflexibility, at BRL 800.00/MWh).
The comparison between the two trajectories evidences a change in the level of the sectoral charge. In Figure 2, referring to the Base Scenario, the trajectory of reserve energy fixed revenue is observed: after reaching its maximum around BRL 20.3 billion in 2030 (in nominal terms), total fixed revenue begins a decline and stabilization trajectory, retreating to the level of BRL 14.5 billion in 2036, in nominal terms, as old contracts expire.
Figure 2 – Evolution of reserve energy fixed revenue in the scenario without PL
Source: TR Soluções' SETE platform.
In Figure 3, the impact of including the new fixed revenue estimated by PL provisions from 2032 onwards becomes clear. In 2036, the first year in which all new plants would be in full operation, reserve energy fixed revenue would exceed BRL 63 billion, in nominal terms. Costs from PL 5.017 would account for more than 77% of this amount.
Figure 3 – Evolution of reserve energy fixed revenue including the PL
Source: TR Soluções' SETE platform.
To represent a long-term condition of the short-term market, a reference PLD of BRL 132/MWh was adopted. The value was obtained from a series composed of monthly values realized since January 2016 and 12 additional months of projection. For each submarquet, the monthly median of the resulting series was calculated, with BRL 132/MWh corresponding to the average of the medians obtained for the SE/CO submarquet.
To isolate the direct effect on the residential captive consumer, the simulation focused exclusively on the B1 Residential subgroup, considering the reference date of 2036, the year of full maturation of procurements, and using this reference PLD to estimate the revenue obtained from reserve energy liquidation in the short-term market. The result is an estimated average tariff impact of 5% in 2036.
This impact is equivalent to an increase of nearly BRL 60/MWh in the Reserve Energy Charge (EER), to be shared among users subject to the charge. Since EER is shared in BRL/MWh, its percentage impact on the tariff tends to be greater at higher voltage levels, where the total tariff is relatively lower.
This result shows high sensitivity to the PLD trajectory. With other assumptions held constant, lower PLD values reduce the revenue obtained from reserve energy liquidation in the short-term market and, consequently, increase the share of costs to be recovered through EER. The opposite movement occurs in high PLD scenarios. Therefore, sensitivity to short-term prices alters the charge value to be paid by consumers, but does not modify the economic commitment associated with generation procurement.
As a sensitivity analysis, should the regulatory floor of the PLD in effect in 2026, of BRL 57.31/MWh, be applied to the modeled generation volume, the annual revenue obtained from liquidating the three new procurement blocks would be reduced by approximately BRL 4.1 billion relative to the reference scenario of BRL 132/MWh. With other assumptions held constant, this difference would need to be recovered through greater EER collection. The exercise uses the 2026 floor exclusively as a sensitivity reference, not constituting a projection for PLD or its regulatory limits in 2036.
In the opposite direction, in scenarios of elevated short-term market prices, revenue from energy liquidation can substantially reduce the need for EER collection. Considering the reference prices and generation volumes adopted in this study, the combined fixed revenue of the three blocks is equivalent to approximately BRL 650/MWh of generated energy. Thus, in a hypothetical situation in which the average PLD for liquidation remained at this order of magnitude, the revenue obtained in the short-term market could be sufficient to cover practically all modeled fixed revenue. Above this level, liquidation could even generate revenues exceeding fixed revenue, although the actual breakeven point is higher when additional costs are considered, such as those associated with hydrological risk assumed by consumers.
This does not mean, however, that a high PLD scenario implies reduced total energy cost for consumers: the effect described refers specifically to EER and may be the case that elevated short-term market prices produce pressures on other power sector cost components.
In sum, approval of the substitute transforms a relatively stable sectoral charge in terms of fixed revenue and with potential for reduction as old contracts expire into a high and persistent charge, with effects on tariffs over the coming 15 to 30 years.
Final Remarks
The results underscore the importance of shifting the debate from preference for certain sources toward efficiency of sectoral governance. The technical discussion does not reside in the attractiveness of natural gas or small hydroelectric plants, but in preserving the regulatory logic in which investments are guided by the system's actual needs.
Institutional strengthening of the Brazilian power sector is based on coordination between planning (EPE), centralized operations (ONS), regulation (Aneel), and guidelines from the Ministry of Mines and Energy (MME). The maintenance of market predictability and balance depends on strengthening these technical bodies and respecting their coordinated action, ensuring that infrastructure expansion continues supported by rigorous cost-benefit analyses.
In summary, TR Soluções' technical evaluation reinforces that energy supply expansion tends to produce the best results in terms of efficiency and affordability when guided by sectoral planning and fair competition. The preservation of institutional procurement procedures is therefore the surest path for pursuing electricity tariff affordability, supply security, and confidence among power sector participants.