August 13, 2026
PL 5.017/2019: impacts of mandatory procurement on tariffs
Summary
The substitute to PL 5.017/2019 approved by the Senate Infrastructure Services Committee introduces new mandatory procurement obligations for natural gas thermal generation and hydroelectric plants of up to 50 MW. This article analyzes the key 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 the Reserve Energy Charge may experience significant growth from the next decade onward, reaching an estimated average tariff impact of 5% on B1 Residential subgroup tariffs by 2036. The results underscore the importance of ensuring that supply expansion decisions align with the needs identified by sector planning and with competitive procurement mechanisms.
1. Introduction
Since 2021, following the enactment of Law No. 14.182/2021 (Law 14.182), TR Soluções has been monitoring the recurrence of legislative initiatives establishing specific mandatory procurement obligations for electricity generation, frequently with predefined source, location, and operational characteristics. Throughout this period, the company has conducted simulations to assess the tariff impacts of these measures, especially when procurements do not stem from the needs identified by sector planning and traditional competitive mechanisms. The substitute approved by the Senate's Infrastructure Services Committee (CI) for the Bill No. 5.017/2019 (PL 5.017) reframes this debate as central to discussions on sector governance and tariff affordability.
Originally conceived in the Chamber of Deputies to address exclusively tariff aspects applicable to irrigation, aquaculture, and domestic water supply via artesian wells, the text incorporated into the Senate structural themes of supply expansion – specific provisions for contracting natural gas thermal plants and hydroelectric plants of up to 50 MW – as well as adjustments to the Energy Reallocation Mechanism (MRE) and guidelines for innovation and research at the National Electric Energy Agency (Aneel).
From the perspective of supply and allocation of sector costs, the text establishes three blocks of mandatory procurement:
- Thermal generation from natural gas of Amazonian origin in the North region, in an amount equivalent to the difference between the installed capacity and the physical guarantee of local structural hydroelectric plants, with operational modulation managed by the National Electric System Operator (ONS).
- Procurement of 4,900 MW in hydroelectric plants of up to 50 MW, with contracts of 25 years and supply schedule between 2032 and 2035.
- 2,500 MW in gas plants with minimum inflexibility of 70%, with procurement by the first quarter of 2027 and operational startup by July 2032.
In all cases, the resulting costs are apportioned among the users of the Interconnected National System (SIN), except those in the low-income residential subclass.
The legal imposition of specific generation expansion blocks represents a trend observed in the power sector in recent years, including Law 14.182, the legal framework for offshore wind generation (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 the procurement of new plants and sector planning. The ex-ante definition of source, location, inflexibility level, and cost allocation restricts the space for sector planning and competitive mechanisms to define least-cost expansion alternatives, pillars of efficient risk allocation in the sector and of tariff affordability.
Quantitative studies developed by TR Soluções validate this premise. In prior simulations on mandatory procurement scenarios, such as the article published in September 2025, it was identified that the fixed allocation of guarantees and reserve charges tends to produce significant impacts on tariffs.
In this study, which specifically analyzes the potential tariff impact 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 raise systemic costs.
2. Thermal generation with gas of Amazonian origin
The substitute provides for the conduct of specific auctions for thermal generation from natural gas of Amazonian origin in the North region. The mechanism links 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 under 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 enterprises and does not constitute, in regulatory terms, 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 requirement for inflexible natural gas thermal generation established in the Ten-Year Energy Expansion Plan (PDE 2035), issued by the Energy Research Company (EPE).
The argument in favor of contracting thermal plants fueled by gas is that this thermal generation was already foreseen by official planning. This point requires a methodological caveat. The reference scenario of the PDE 2035 incorporates 7,246 MW of inflexible gas thermal plants because it was prepared under the normative mandate of Law 14.182. However, when the EPE conducts simulations uncoupled from these mandatory procurements — as demonstrated in the sensitivity to Law 15.269 presented in the PDE 2035 itself — the lowest-total-cost expansion path does not include new inflexible thermal plants by 2035, as they prove uncompetitive from a technical-economic standpoint.
It is therefore incumbent on the legislature to clarify whether the 60% constraint applies to the reference trajectory of PDE 2035 (linked to the history of Law 14.182) or to the requirement strictly identified by planning models without legal mandate.
This study assumes the 60% applies to the inflexible expansion of the reference scenario of PDE 2035 (7,246 MW), so that the maximum resulting volume would be 4,348 MW.
To measure the economic and tariff impact of this procurement, a value of BRL 800/MWh was adopted for simulation purposes as the reference for the average total cost of delivered energy (fuel, capital, and operations). This assumption is grounded in concrete sector benchmarks:
- Historical auctions in isolated/Amazonian systems: in the Roraima Supply Auction (2019), which enabled UTE Jaguatirica II using gas from the Azulão field (AM), the average price was BRL 833/MWh.
- Cost Parameters of PDE 2035: the unit variable cost (CVU) of flexible gas thermal plants estimated by EPE reaches BRL 1,000/MWh, while inflexible plants exhibit CVUs between BRL 430/MWh and BRL 490/MWh, to which must be added fixed investment costs and transportation logistics.
A potential procurement of 4,348 MW at the reference price of BRL 800/MWh, with inflexibility of 51%1 (complement to the capacity factor of structural hydroelectric plants), would result in approximately 19.4 TWh/year of inflexible generation, corresponding to a cost on the order of BRL 15.5 billion per year.
3. Procurement of hydroelectric plants of up to 50 MW
The substitute text establishes the mandatory procurement obligation of a total amount of 4,900 MW in small-scale hydroelectric plants, requiring that the auction for procurement be conducted by the Executive Power within 12 months of the new law's publication (superseding the expiration of the first quarter 2026 deadline of current legislation, which provides for mandatory procurement of 3,000 MW from the source). The supply startup schedule, under 25-year contracts, is distributed as follows: 2,000 MW starting supply in 2032; 1,000 MW in 2033; 1,000 MW in 2034; and 900 MW in 2035.
In parallel, the project modifies the monetary adjustment rule for the reference price ceiling. While current rules provide for full adjustment by the Construction Cost Index (INCC) in the pre-auction phase, the new text introduces a hybrid indexer composed of 50% INCC and 50% IPA (Agricultural Price Index) in the period preceding the auction, maintaining full IPCA adjustment for contract restatement during the supply phase.
Taking as initial reference the price of BRL 392.84/MWh observed 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 assumption for the auction, the opening price is estimated at BRL 429.00/MWh.
Full procurement of 4,900 MW at this reference value, under a capacity factor of 47% (equivalent to that observed in recent source auctions), results in a volume of mandatory generation of 20.2 TWh/year when all blocks are in commercial operation (from 2036 onward). This corresponds to a total fixed revenue on the order of BRL 8.7 billion per year (at August 2026 prices).
The final effect passed through to electricity bills via a charge will depend on the Settlement Price of Differences (PLD), since the dynamics of this procurement are assumed to follow the pattern 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 regulation.
4. Thermal generation from natural gas with 70% inflexibility
The second thermal front introduced by the PL 5.017 substitute establishes the mandatory procurement of 2,500 MW in new natural gas plants with a minimum annual inflexibility of 70%, over 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 until the first quarter of 2027 and supply startup by July 2032, with mandatory regional distribution among Goiás, Integrated Development Region of the Federal District and Surroundings (RIDE-DF), Rondônia, Triângulo Mineiro, and the Metropolitan Region of São Luís.
The absence of gas transportation 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 costs or freight premiums to the final fuel price.
Furthermore, the imposition of a 70% inflexibility floor mandates 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 obligation of continuous thermal generation reduces the space for accommodating renewable energy in the market, potentially intensifying curtailment episodes and raising the global cost of SIN operation.
The relevance of imposing a 70% minimum inflexibility must also be analyzed in light of the current composition of thermal generation in the SIN. The system already exhibits a significant share of thermal generation associated with inflexibility, reducing the available space for this fleet to respond to economic signals and operational needs of the system.
Figure 1 illustrates thermal generation by dispatch reason, on a daily basis, between January 1, 2021, and July 9, 2026. In 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 high 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 show, therefore, that the introduction of new thermal blocks with high inflexibility would occur in a system where a significant share of thermal generation already operates with limited responsiveness to economic dispatch signals. During periods of high renewable generation availability, the expansion of this share can reduce operational flexibility of the SIN and increase the need for generation curtailment 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.
To assess economic impacts, a reference average price of BRL 750.00/MWh in today's values was adopted as the estimate. This price is based on PDE 2035 parameters, considering fixed O&M, taxes, investment amortization, and logistics. Thus, the annual fixed revenue to meet this procurement would be on the order of BRL 11.5 billion.
5. Potential tariff impacts of the 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. Similarly, the prices adopted for new procurements constitute references for simulation purposes and do not represent estimates of prices that will effectively result from future auctions. These values may vary depending, among other factors, on financing conditions, fuel and logistics costs, level of competition, project configuration, and conditions established in the bidding documents. The following scenarios were modeled:
- 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 for in Law 15.269. It is important to note 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 (PL 5.017 substitute): 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 thermal plants with 70% inflexibility (1,750 MWm, at BRL 750/MWh), and incorporates Amazonian gas generation (approximately 4,348 MW or 2,217 MWm with 51% inflexibility, at BRL 800.00/MWh).
The comparison between the two trajectories reveals a shift to a higher level of the sector charge. In Figure 2, concerning the Base Scenario, the trajectory of reserve energy fixed revenue is observed: after reaching a maximum point around BRL 20.3 billion in 2030 (in nominal terms), total fixed revenue begins a declining and stabilization trajectory, receding to BRL 14.5 billion in 2036 in nominal terms, as older 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 new fixed revenue estimated by the PL provisions starting in 2032 becomes clear. In 2036, the first year in which all new plants would be in full operation, reserve energy fixed revenue would surpass the mark of BRL 63 billion in nominal terms. Costs relating to PL 5.017 would account for over 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 submarked, the monthly median of the resulting series was calculated, with the BRL 132/MWh corresponding to the average of medians obtained for the SE/CO submarked.
To isolate the direct effect on the captive residential consumer, the simulation focused exclusively on the B1 Residential subgroup, considering the base date of 2036, the year of full maturity of procurements, and using this reference PLD to estimate the revenue obtained from settlement of reserve energy 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 apportioned among users subject to the charge. As the EER is apportioned in BRL/MWh, its percentage impact on tariff tends to be greater at higher voltage levels, where the total tariff is relatively lower.
This result exhibits high sensitivity to the PLD trajectory. With other assumptions held constant, lower PLD values reduce the revenue obtained from short-term market settlement of reserve energy and, consequently, increase the portion of costs to be recovered through the EER. The reverse movement occurs in high-PLD scenarios. Therefore, sensitivity to short-term price alters the value of the charge to be paid by consumers, but does not change the economic commitment associated with generation procurement.
As a sensitivity test, if the regulatory floor of the PLD in effect in 2026 of BRL 57.31/MWh were applied to the modeled generation volume, the annual revenue obtained from settlement of 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 have to be recovered through greater EER collection. The exercise uses the 2026 floor solely as a sensitivity reference, not constituting a projection for the PLD or its regulatory limits in 2036.
In the opposite direction, in scenarios of elevated short-term market prices, revenue from energy settlement 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 amounts to approximately BRL 650/MWh of generated energy. Thus, in a hypothetical situation in which the average PLD of settlement remained at that order of magnitude, the revenue obtained in the short-term market could be sufficient to cover nearly the entire modeled fixed revenue. Above that threshold, settlement could even generate revenues exceeding fixed revenue, although the effective break-even 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 the EER, and elevated short-term market prices may produce pressures on other components of power sector costs.
In summary, approval of the substitute transforms a sector charge relatively stable in fixed revenue terms and with potential for reduction as older contracts expire into an elevated and persistent charge, with effects on tariffs over the next 15 to 30 years.
Final Considerations
The results reinforce the importance of shifting the debate from preference for particular sources to the efficiency of sector governance. The technical discussion does not reside in the attractiveness of natural gas or small-scale hydroelectric plants, but in the preservation of the regulatory logic in which investments are guided by the actual needs of the system.
The institutional strengthening of Brazil's power sector rests on coordination among planning (EPE), centralized operation (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 performance, ensuring that infrastructure expansion continues supported by rigorous cost-benefit analyses.
In summary, TR Soluções' technical assessment reinforces that expansion of energy supply tends to yield the best results in terms of efficiency and affordability when guided by sector planning and isonomic competition. Preservation of institutional procurement procedures is, therefore, the most secure path toward seeking tariff affordability, supply security, and confidence among power sector agents.