The Energy Regulation and Markets Review: Brazil


The Brazilian electricity sector, which operates under an integrated and hydrothermal system and with a strongly established free market, is founded on a regulatory framework that provides investors with considerable safety. The market underwent a major restructuring process in the 1990s, when it was opened for private investment and was submitted to further regulatory reform in 2004. Security of supply, regulatory stability and competitiveness provide the basis for the regulatory framework.

The main power source used in Brazil is hydropower (51.15 per cent of the installed capacity, excluding small plants), while thermal power plants have an important role in complementing the mix and assuring the security of supply (23.99 per cent of the installed capacity).2 In addition, alternative power sources, notably wind, biomass, and solar, have gradually increased their share and gained additional importance in the electricity portfolio. Renewable energy has been encouraged by special tariff discounts and has become more competitive during the past few years, as evidenced by the latest power auctions.

The electricity system is connected by transmission facilities that enable electricity produced in the remote areas of a continent-sized country like Brazil to be transported to major consumers' markets, mainly located in the south-east. The grid has its operation centrally coordinated and controlled, to reduce global costs and enhance the security of supply, especially during dry seasons.


i The regulators

The federal government is empowered by the Constitution to provide services and facilities within the power sector. Private companies are entitled to enter the market through government delegation by concession, permission, or authorisation.

The main government body responsible for formulating public policies within the energy and mines sectors is the Ministry of Mines and Energy (MME). There are currently other arms of the federal government that have an important role in this sector, namely:

  1. the National Council on Energy Policy, which is the presidential cabinet for energy policy affairs created by Law 9,478/1997; and
  2. the Committee for Monitoring of the Electricity Sector, part of the MME, which was created mainly as a response to the rationing in 2001 (by Law 10,848/2004) and is responsible for monitoring security of supply and suggesting correction measures.

Since the market's liberalisation, the industry's participants have been regulated by the National Electric Energy Agency (ANEEL),3 which has been granted autonomy by central government but is nevertheless attached to the MME. ANEEL, created by Law 9,427/1996, regulates, and supervises power generation, transmission, distribution, and trading activities to ensure the correct balance between the interests of companies and consumers.

The agency is responsible for implementing the policies and guidelines outlined by the MME, and for monitoring the activities developed in the sector by verifying compliance with its rules and regulations and supervising contract performance. Some of ANEEL's activities are undertaken by delegation from the MME, such as the carrying out of power auctions and the granting of certain regulatory licences. It is important to note that the performance of complementary supervision activities may be decentralised to state regulatory authorities, under the terms established by law.

ANEEL is managed by an executive board composed of a managing director and four other directors, is organised into technical divisions and is charged with performance of administrative functions in various areas, such as economic regulation, market studies, supervision, mediation and the granting of concessions and authorisations.

The restructuring processes undergone by the power sector have involved the creation of new institutional authorities. The National Electric System Operator (ONS) was created by Law 9,648/1998 as a non-profit association to coordinate and control the operations of the electrical grid; its governance system was granted even more independence as part of reforms in 2004. Under the previous regulatory framework, an operational institution was created to manage the wholesale market, which was succeeded by the Electricity Trading Chamber (CCEE) following 2004's regulatory reform. The CCEE, introduced by Law 10,848/2004, is mainly responsible for the registration of power purchase agreements (PPAs), and for the measurement, accounting, and financial settlement of electricity trading operations. Within 2004's reform, another institutional entity was created: The Energy Research Company (EPE), a publicly held company responsible for studies and research on the energy industry with a view to enabling planning within the sector, as foreseen in Law 10,847/2004.

ii Regulated activities

Since the federal government has the authority to provide electricity services and facilities, private companies need government approval to enter the market. The regulatory licence required for entrepreneurs to operate in the power sector depends mainly on the segment (generation, transmission, distribution, or trading) to be joined, and the extent to which regulation is exercised in each of them. Under the provisions of the legislation currently in force, the MME is the granting authority and may delegate its powers to ANEEL.

Power generation may be operated by means of a concession of use of public assets, a public service concession, an authorisation or even a communication. The regulatory licence required, and the applicable regime depend on the plant's installed capacity, the power source and the size of the reservoir (a requirement for hydropower plants). Given that regulation of the power sector is constantly evolving, there are several legal frameworks in existence, each from different points in time. As a result, the rules relevant to one power plant may not apply to others, even though they fall under the same regimen. The specifics of the applicable law must always be assessed individually, alongside the provisions of the specific concession agreements.

In general terms, as for new large hydropower plants (HPPs) that have an installed capacity in excess of 50MW, the entrepreneur must participate in power auctions to be granted a concession to operate new generation projects (new project auctions) and is required to sell a minimum percentage of the plant's output on the regulated market (the remainder may be sold on the free market). The bid entitles the winning bidder (selected by lowest price criteria) not only to operate the new project (by being granted with a concession of use of public asset), but also to sell electricity to the distribution companies participating in the auction. Companies with hydropower plants in operation may participate in power auctions conducted specifically for purchasing electricity from existing projects (existing project auctions) or may sell their output on the free market.

However, authorisation is required for companies willing to operate small hydropower plants (SHPPs) – which have an installed capacity of up to 30MW and a small reservoir – and plants with a capacity of not more than 50MW that do not have HPP characteristics. Although the granting of authorisation does not require an auction, the existence of more than one interested company in the same hydroelectric potential triggers a competitive process by which ANEEL selects the entrepreneur, under the provisions of ANEEL's regulations.

Other energy sources, such as thermal, wind and solar, are subject to an authorisation regime, for which the process is conducted by ANEEL. All of these, including hydropower plants subject to authorisation, may participate in power auctions (either new project, existing project, or backup energy auctions) to sell their production on the regulated market, or may sell it in the free market.

Small plants – with an installed capacity of up to 5MW for thermal and renewable energy, including hydropower plants – do not need authorisation, but require a communication to ANEEL, considering their reduced impact on the system.

The regulatory licences mentioned (except for new hydropower concessions, currently only operated by independent producers) can be granted either under an independent power production regime or under a self-production regime.4 The table below gives a general summary of the regulatory licences required by private investors to enter the Brazilian power generation segment.

Regulatory licences needed by power generation companies
Power sourceInstalled capacityRegulatory licence
HydropowerGreater than 50MW or with large reservoirsConcession for use of public asset (preceded by a public auction)
Greater than 5MW but not greater than 50MW (depending on reservoir size)Authorisation
Up to 5MWCommunication
Thermal power plants and renewable energy (except hydropower)Greater than 5MWAuthorisation
Up to 5MWCommunication

There are currently discussions on whether private investors can participate in nuclear power plants in the country. It has long been understood that private participation is forbidden on account of the federal government's operation monopoly, foreseen in the Constitution. For that purpose, the state-owned company Eletrobrás has a subsidiary, Eletronuclear, which operates the two nuclear power plants that are currently active. However, more recent opinions argue that the Constitution establishes the monopoly of limited parts of the supply chain, such as research, extraction, enrichment, reprocessing, manufacturing and trade of nuclear mining and metals, which would be restricted to the federal government, and that private partners could participate, for example as partners of Eletronuclear. Furthermore, Law No. 14,120, of 1 March 2021, recently enacted, provides a change in relation to the grant for thermonuclear exploration (called Angra 3) that depended on authorisation from the National Energy Policy Council (CNPE). The Law provides for a 50-year concession period for Angra 3, extendable for another 20 years, and sets forth that a power purchase agreement with duration of 40 years will be executed for backup energy with costs shared among all energy consumers.

Power transmission and distribution activities are considered natural monopolies, given their dependence on the electrical grid. Therefore, most Brazilian power distribution consumers are still legally locked into purchasing energy from only one intermediary: the local distribution companies to which they are connected. In addition, considering their importance, their operation requires a public service concession, preceded by a mandatory public bid.

Power trading companies wishing to operate in the power market need authorisation under the provisions established by ANEEL's regulations.

Consumers need a minimum load to participate in the free market of electricity. The lower limit is being reduced and is currently 1.5MW. There is a class of 'special consumers' for those that use between 500kW and 3MW that may migrate to the free market under the strict condition of purchasing their energy supply from 'special energy' sources only, which include solar, wind, biomass and hydro with a maximum capacity of 50MW. Consumers who cannot or have not migrated to the free market are bound to purchase energy from their local power distribution company and are referred to as 'captive consumers'.

iii Ownership and market access restrictions

The Constitution establishes that hydropower generation activities must be carried out by Brazilian citizens or companies organised under Brazilian laws, with headquarters and managing offices located in Brazil. The bidding rules of electricity auctions usually do not forbid the participation of foreign companies, but normally establish that:

  1. foreign companies shall organise a special purpose company under Brazilian law to have the regulatory licence granted; and
  2. if foreign companies bid jointly with a Brazilian company in a consortium, the leadership shall always be exercised by the Brazilian company.

In addition, the bid notice usually establishes that foreign companies shall have a legal representative in Brazil with powers to receive service of process and provide answers in the judicial and administrative spheres, as well as represent them in all phases of the proceedings.

Legislation does not forbid electricity companies, organised under Brazilian laws, from being controlled by foreign companies or private equity investment funds organised under foreign legislation (except for nuclear power plants). ANEEL requires, however, also that these companies have a legal representative in Brazil, duly vested with powers to receive service of process and provide answers in the judicial and administrative spheres.

Also, there are specific restrictions for the activities of power distribution companies. When the market was restructured in the 1990s and later reformed in 2004, the Law imposed limits on their participation in other activities within the supply chain, in order to avoid conflicts of interest. As such, generation and distribution companies operating in the interconnected system are required to maintain separate legal entities and individual accounting, although they may be part of the same corporate group or share infrastructure and human resources when authorised by ANEEL.

iv Transfers of control and assignments

As a rule, the transfer of a regulatory licence or of a controlling interest5 in an industry participant is subject to ANEEL's prior consent, mainly to adhere to the bidding process and transparency principles.

The regulation in force (ANEEL Resolution 484/12) sets forth that the prior consent of the regulatory agency is required for transfer of controlling interests of public service providers, hydropower companies and nuclear-fuelled energy companies, as well as in any companies, regardless of the power source, whose intended controlling company makes up the corporate group holding or which, with the intended transaction, becomes the holder of 'a significant share of the power generation market for the safety of the regulated market'6 – a concept yet to be established by the regulatory agency. Some transactions are exempt from consent, under the terms established by ANEEL's regulations. Nonetheless, the exempt agent has a deadline within which to inform ANEEL of the implemented transaction and may be required also to maintain a dossier available for inspection.

The rules currently in force may be further amended after forthcoming regulation by the regulatory agency on how 'a significant share of the power generation market for the safety of the regulated market' is enacted. This matter has been under discussion at the regulatory agency for a while, without any formal pronouncement yet.

Transmission/transportation and distribution services

i Vertical integration and unbundling

Segregation of the different levels of the production chain was implemented mainly to promote efficiency and competitiveness, after it had been proven that the vertically integrated industry was unable to provide services efficiently. The unbundling between power generation, transmission and distribution was formally adopted by the restructuring undertaken in the 1990s and further enhanced under the 2004 regulatory framework.

The primary purpose of the unbundling in the sector was to encourage competition in the generation and trading segments (which may be provided under competitive regimes), whereas transmission and distribution segments remain natural monopolies. Since the restructuring during the 1990s, separation of the contracting of access to the grid and the purchase of electricity had already been adopted as an unbundling measure.

The current regulatory framework also requires that distribution activities be undertaken by separate legal entities of transmission and generation activities, with specific restrictions on the corporate structure of their economic groups (see Section II.iii).

Currently, there is no legislation in respect of unbundling between the generation and transmission segments, nor any that restricts economic groups from having companies in several segments. Furthermore, distribution companies still have a monopoly in both electricity transport and electricity trade in respect of those consumers designated as 'captive consumers' in their concession area.

A different kind of unbundling has been under discussion recently, in respect of the future expansion of the free power purchase market, namely the unbundling of distribution services, to limit the distribution monopoly to just electricity transport in the respective concession area. Based on current timelines, such unbundling shall take place until 2024.

ii Transmission/transportation and distribution access

Distribution and transmission companies are subject to regulation of access to their respective grids to avoid discrimination and eliminate barriers to entry. The regulatory framework requires that network companies share and provide access to 'essential facilities' to segregate the service provision from the corresponding infrastructure management. For this reason, the electricity sector is governed by the principle of open access to the electricity grid, upon reimbursement of the cost incurred with reinforcement works needed for the connection and payment of the electricity grid use tariff. Despite the open access regulation, there is currently a limited offer of connection points for new generation projects, although the transmission grid is always expanding as a result of the annual auctions conducted by the government. ANEEL is also discussing regulations to possibly compensate power plants subject to grid curtailments, under certain conditions.

iii Rates

Power transmission and distribution companies are subject to price regulation, and thus have their revenues calculated by ANEEL, which aims to set prices to promote economic efficiency as if the segments were competitive rather than characterised as natural monopolies.

Rates are based on a price-cap mechanism (revenue cap for transmission companies) and thus are subject to adjustment by an inflation rate. The initial rates or revenues are established in the concession contract resulting from either the auction's competitive process (applicable to new transmission assets) or the privatisation process.

After the initial rates or revenues have been set, they are subject to annual adjustments for inflation, periodic reviews (every four or five years, depending on the concession contract) and possibly to further extraordinary reviews to restore the concession's balance upon ANEEL's approval.

Rates can be also adjusted to consider an 'X factor'. Under this regime, concessionaires are encouraged to be more efficient by reducing costs up to the following price review, when new pricing levels are defined by ANEEL. The price control review process essentially aims to set new efficiency standards for operational costs and investment returns, to ensure that private companies receive an adequate remuneration and that consumers pay a fair price for their electricity. The new standards established will be valid for the new period up to the following price review.

Energy markets

i Development of energy markets

The 2004 restructuring process that resulted in the current regulatory framework for the Brazilian power sector envisaged two markets in which participants are able to sell power: the regulated market and the free market.

Within the regulated market, generation companies sell power to distribution companies, which participate as buyers in public auctions conducted by the government. Generation companies compete against each other according to the rules of each auction by the lowest bid price (BRL/MWh) to sell power to the distribution companies. As mentioned above, new-project auctions also involve the granting of concessions or authorisations to enable the winning bidders to operate new power plants.

The regulated market serves the captive consumers. In other words, the power bought by distribution companies in the auctions is purchased by captive consumers (those defined as not having any choice in selecting their power supplier) or potentially free consumers (those that have not yet migrated to the free market even though they meet the criteria). As a rule, distribution companies are obliged to buy power on the regulated market (apart from a few legal exceptions) and to ensure that 100 per cent of their consumers' demand is met.

There are three main types of auctions within the regulated market:

  1. New Project Auctions (LEN), conducted to promote power generation expansion sufficiently in advance to enable plant construction, to meet growth in market consumption;
  2. Existing Project Auctions (LEE), conducted to contract power produced by existing projects, to reduce the financial risks for distribution companies in their demand projections; and
  3. Backup-Energy Auctions (LER), conducted to increase security of power supply.

The auctions are known as 'A minus N', where 'A' is the year in which the plant must enter operation and start delivering power to the grid. Auctions for new projects may include HPPs designated by the government, but companies usually also participate with their own projects (SHPPs, thermal, wind, biomass and solar projects, depending on the auction rules), which need prior technical qualification before the EPE to be entitled to participate in the auctions. In auctions for existing projects, generation companies with projects in operation and trading companies may sell power within the regulated market. Finally, backup energy auctions exist to ensure security of supply to the electricity system, and is usually contracted from SHPPs, wind and biomass plants.

Within the free market, power is freely traded between those parties entitled to participate in it: generation and trading companies, and free and special consumers. As mentioned, free consumers are those who may choose their power generation supplier, whose demand is currently higher than 1.5MW. According to an Ordinance issued by the MME in December 2018, as amended in 2019, this load requirement has been reduced and will continue be reduced in the coming years. The first reduction occurred in July 2019, when free consumers were required to have demand higher than 2.5MW, and the second was in January 2020, when it dropped to 2MW. The demand requirement will be reduced further: in January 2021 to 1.5MW, in January 2022 to 1MW and in January 2023 to 500kW.

Special consumers, which may constitute a single consumer or group of consumers that share the same interests, are required to have a demand higher than 500kW and may only choose their supplier when buying from specific renewable sources.

ii Energy market rules and regulations

Sector participants that carry out power trading transactions are obliged to comply with the sector's rules and regulations. As a result of the 2004 regulatory reform, participants must prove that 100 per cent of the power sold in PPAs is associated with generation plants of their own or belonging to third parties (by means of PPAs to purchase from them), according to the terms set forth by Decree 5,163/2004. Whereas distribution companies need to serve 100 per cent of their market's demand, sellers need to produce or purchase the same amount as sold under PPAs, and consumers need to purchase the same amount consumed.

If they are not able to produce or purchase the total amount of power traded or consumed, participants will be exposed to the short-term market, in proportion with the amount not produced or purchased, to cover their original PPAs. Financially exposed participants are:

  1. obliged to pay the amount equivalent to the difference between the power contracted and the power delivered or consumed (not covered in additional PPAs), multiplied by the price of financial settlement of differences (the PLD), which is defined weekly by the CCEE;7 and
  2. may be subject to penalties imposed by the CCEE.8

The amount of power allocated to each generation plant is determined by its assured capacity, defined as the maximum amount of power that the plant is allowed to sell and is committed to deliver under PPAs.9 This calculation is very important as it sets the limit on the power available for sale (originating from the plants' own power generation).10

The operation of the Brazilian interconnected system may cause a dissociation of the participants' contractual commitments from the actual physical delivery of the power traded. Power production mainly depends on operational decisions made by the ONS, since several power plants are subject to centralised dispatch, which reduces the control that companies have over their own plants' output. A few regulatory mechanisms have been established to mitigate this risk and avoid these participants facing financial exposure for reasons they cannot manage, such as the energy reallocation mechanism that is applicable to hydropower plants.

iii Contracts for sale of energy

Within the regulated market, because of the auction process, long-term PPAs are executed between the generation companies that have won the bid and the distribution companies buying at the auction. Similarly, in backup energy auctions, a backup energy agreement is executed between the sellers and the CCEE, as the representative of all consumers. All contractual conditions – including supply period, rates (set by the low-bid award criteria) and amounts – are defined within the bid process and are not subject to negotiation.

The contracts' effective terms depend on each type of auction and power source and may vary from 15 years to 35 years for new-project auctions, from one year to 15 years for existing-project auctions, and for up to 35 years for backup energy auctions. The PPAs may be executed under one of two modes: quantity or availability. Under quantity contracts, sellers assume hydrological risks (variations between the amounts contracted and effectively produced) and deliver the power sold at the submarket where the plant is located. Under availability contracts, buyers assume the risks deriving from the plant's unavailability resulting in production that is lower than the amount contracted.11

It has become increasingly common to have long-term PPAs in the free market that make the construction of new plants financially feasible. There is even a specific practice allowing a producer who is also the consumer to receive exemption of certain sectorial charges (self generation). Within the free market, participants execute PPAs in which they freely establish the conditions, supply period (short, medium or long term), price and amounts, provided that the contractual terms comply with the sector's rules and regulations, particularly the CCEE's trading rules and procedures.

iv Market developments

Some developments have been made recently. While changes in the regulation on distributed energy and net metering may discourage new participants in this segment, new investment in renewables as centralised generation are being fostered by Provisional Measure No. 998 of 1 September 2020, recently enacted as Law No. 14,120 of 1 March 2021. According to this new Law, the government will continue to grant grid discounts for renewable projects for a limited time: only for power plants requesting the power sector licence within 12 months from the date the law is enacted and entering into operation within 48 months from the date the licence is issued. After being granted, the projects remain entitled to the benefits until the end of the licence's validity (usually of 35 years). The law also outlines the creation of a new incentive for sources with low carbon emissions, although such a mechanism is yet to be detailed.

We have also noted a trend towards long-term renewable PPAs, which can obtain renewable energy certificates (REC), and self-generation projects, which entitle the exemption of certain sectorial charges.

Renewable energy and conservation

i Development of renewable energy

One of the most significant regulatory policies adopted to encourage the development of renewable power in the past has been Proinfa, an incentive programme to encourage the use of alternative power sources, created by Law 10,438/2002. This programme was based on feed-in mechanisms to contract wind, biomass and SHPP projects for 20 years. According to the programme regulations, a total of 3,300MW was expected to be contracted under the first phase of Proinfa. The second phase aimed to achieve 10 per cent of the annual energy consumption deriving from renewable sources until 2022, excluding large HPPs. For the current year, the incentive is evaluated in an amount of 4 billion reais. Proinfa costs are shared among all energy consumers, except low-income consumers.

Pursuant to information made available in the 2020–2029 Energy Plan,12 the EPE forecast that in 2029 the installed capacity of distributed generation and net metering would reach 32GW if there is no change in regulation. However, current discussions would suggest that the projection for 2029 is more likely to reach 11GW of installed capacity. This will still represent a significant proportion, amounting to 2.3 per cent of the total installed capacity in Brazil. The segment handled more than 2 billion reais in investments in 2018. Although solar is the most common source, it also expected that wind, hydropower, and thermal projects will increase in the coming years.

Wind power is the source that has been most prevalent and has grown the most in regulated auctions. The EPE has stated in the Energy Plan that, although wind power has become more competitive in price, the competitiveness of SHPPs has decreased particularly because of environmental and construction risks. As for solar energy, its installed capacity is still not significant but is also expected to grow.

Renewable energy sources are entitled to some regulatory benefits (such as a discount on fees for use of the electrical grid, and the option of selling power to special consumers, under the terms established by law) and to some special credit lines from the National Bank for Economic and Social Development. Benefits will change in the future as the sources become more competitive, as was set in Provisional Measure No. 998, of 1 September 2020, recently enacted as Law No. 14,120 of 1 March 2021 (see Section IV.iv).

The Special Incentives Regime for Infrastructure Development, known as REIDI, is a federal tax incentive scheme for the development of infrastructure that lasts for five years and is applicable to the purchase of equipment related to power generation and transmission projects, including those involving renewable energy, under conditions established by legislation. At the federal level, a tax incentive is granted for 'infrastructure debentures' as well. There are also some tax incentives granted by the states to encourage the development of renewable sources.

ii Energy efficiency and conservation

The Brazilian power market increased in efficiency during the 2001 rationing, when the market learned how to reduce the consumption required by the government. As the market has suffered unfavourable hydrological conditions in recent years, broad awareness campaigns about the country's exposure to water shortages have been conducted, possibly as a way of encouraging energy-efficiency measures without recourse to stricter rationing control.

In addition, since January 2015, power rates have been subject to a band pricing scheme, which, by allowing customers to be charged more when the system incurs higher generation costs, represents an important incentive for demand reduction.13 Moreover, a new pricing scheme is available as from January 2019 for certain consumers (namely those who consume more than 250kWh), while others will have the option from 2020. This pricing scheme is also referred to as an hourly tariff or white tariff and allows users to pay different rates according to the time and the day of the week of their consumption.

Finally, since January 2021, the settlement price for differences (PLD), a sort of locational margin price, is calculated by the Electricity Trade Chamber on an hourly basis, instead of a weekly basis. ANEEL believes that these changes will improve and rebalance the utilisation factor of the system.

iii Technological developments

The Brazilian market has taken some important steps towards the implementation of smart grid technologies and batteries. New technologies should also foster investments in renewables in Brazil. Offshore wind power plants started to gain traction in 2020, and around seven projects have already requested environmental licensing. Green hydrogen is also expected to advance major market opportunities, and at least one large project is being studied in the Port of Açu. The Hydrogen Council estimates that Brazil can take the lead for green hydrogen, due to the fast expansion of renewables in the country. In addition, the Brazilian National Energy Policy Council defined the technology as strategic to the country, which means that more research and development (R&D) projects will be funded on the matter in the following years with resources from mandatory R&D investments of public services concessionaires.

The year in review

2020 was marked by the global spread of covid-19. Based on the state of public calamity recognised by the Legislative Decree No. 6/2020, the federal government enacted the Provisional Measure No. 950 of 8 April 2020, aiming to secure energy supply for low-income consumers and softening tariff impacts for all consumers, while at the same time addressing the loss in revenue suffered by power distribution companies due to an increase in defaults.

Amid uncertainties in the market, the Brazilian government and power sector authorities, in particular the Ministry of Mines and Energy and ANEEL, responded quickly, alongside a syndicate of banks led by the Brazilian Development Bank (BNDES), to structure what became the first centralised credit facility related to covid-19 in the country. Conta-Covid, the name given to the 15.3 billion reais credit facility, was systemically relevant to the Brazilian electricity market, because its immediate beneficiaries, power distribution companies, are the endpoint to around 70 per cent of the energy supply chain in the country and account for the largest part of payments to power generators and power transmission companies.

ANEEL has also shown consideration for the unique context, with a series of measures to reduce tariff impacts and to extend work deadlines for power transmission concessionaires.

The effects of covid-19 in the market did not hinder investments, quite the opposite. As mentioned in Section IV.iv, Law 14,120 of 1 March 2021 encourages investments in renewables since it establishes a turning point for projects authorised before and after March 2021. In addition, the exchange rate and relatively low interest rates have encouraged investments in the power sector.

During the period in review, the Ministry of Mines and Energy postponed the auction for new power generation projects to 2021, due to the revision in expected demand. One transmission auction was successfully conducted for 14 lots, representing almost 2,000 kilometres of transmission lines, and an estimated investment of 7,346,390,000 reais.

Privatisation of state-held energy companies was also successfully conducted in 2020, including of the acquisition, by Neoenergia, of the distribution company CEB Distribuição SA (CEB-D), responsible for the concession area of Brasília-DF, and the acquisition, by Equatorial, of the distribution company Companhia Estadual de Distribuição de Energia Elétrica (CEEE-D), with activities mostly in the state of Rio Grande do Sul.

Conclusions and outlook

Activity on the Brazilian electricity market continued to be eventful in 2020. The sector has been trying to adjust to the new social and economic situation, and important transactions can be expected in the near future. Competition and the number of new foreign bidders entering the market is expected to continue to increase.

In addition, the MME defined a long-term schedule, detailed below, for next year's energy auctions from new projects (LEN) and energy from existing projects (LEE):

2021JuneLEN A-3 and A-4
LEE A-4 and A-5
Transmission auction
SeptemberLEN A-5 and A-6
DecemberLEE A-1 and A-2
Transmission auction
2022AprilLEN A-4
JuneTransmission auction
SeptemberLEN A-6
DecemberLEE A-1 and A-2
Transmission auction

Certain large companies are likely to be privatised in the coming years, such as the generation and transmission branches of CEEE, and possibly Eletrobrás subsidiaries, Cemig and Copasa.

In addition, investment in centralised renewable projects and self-generation is expected to continue growing. Furthermore, the expansion of the free market is already set forth in the regulations, with reduced demand requirements entering into force in January 2022 (to 1MW) and January 2023 (to 500kW). There are also expectations for a full opening of the free market from 2024.

The strength of the Brazilian market's institutions certainly will continue to play an important part in stability. The EPE estimates that investments in centralised power generation in the years 2020–2029 will amount to 303 billion reais, and another 104 billion reais in power transmission and substations.14 In summary, the Brazilian power sector should be viewed as a target for long-term investment, to the extent that investors are knowledgeable of the characteristics of each type of investment and are able to assess the risks involved accurately.


1 José Roberto Oliva Jr is a partner and Julia Batistella Machado is a senior associate at Pinheiro Neto Advogados. The authors want to thank Larissa Pereira Silveira for assistance with the research required to update this chapter.

2 Information provided by the Brazilian electricity regulatory agency (Agência Nacional de Energia Elétrica (ANEEL)) on its power generation data centre – see Sistema de Informações de Geração (SIGA), at (last accessed on 16 April 2021).

3 In a way, the companies were already subject to regulation before the creation of the National Electric Energy Agency [ANEEL], but the previous government bodies lacked effectiveness since they did not have autonomy and were part of central government, which also controlled the state-owned companies that were the main service providers within the sector at the time.

4 The importance of the difference between the two regimes has diminished since independent producers are entitled to consume part of their production and self-producers can sell the unused portion of their own output under the conditions set forth by rules and regulations.

5 The concept of controlling interest adopted by ANEEL is the same as provided in Brazilian corporate law and is associated with prevalence in the company's corporate and managerial decisions.

6 Article 5 (IV) of ANEEL Resolution 484/12.

7 The Electricity Trading Chamber [CCEE] calculates the PLD based on the Operation's Marginal Cost and a variety of criteria established by legislation (e.g., hydrologic conditions) for each submarket and demand level.

8 The CCEE has responsibility for the processes described – the accounting of the market's traded power amounts and the financial settlement of the values involved in short-term market transactions.

9 The assured capacity considers the plant's expected production and excludes events of unavailability and may be lower than the installed capacity of the power plant.

10 Although in the regulated market the assured capacity represents the limit available for sale, participants in the free market can sell an amount above the assured capacity if they have executed PPAs to cover the total amount sold.

11 Under availability contracts, the remuneration consists of a fixed amount for the plant to be available and an additional value that varies according to the plant's effective production.

12 Ministry of Mines and Energy [MME], Energy Research Company [EPE], 'Ten-Year Energy Expansion Plan 2029', Brasília: MME/EPE (2020), p. 13, at (last accessed on 22 April 2020).

13 Green, yellow, and red flags indicate lower, medium and higher generation costs. As a result of the recent water shortages, the Operador Nacional do Sistema Elétrico [ONS] has continuously dispatched high-cost thermal power plants since the end of 2012, and consumers have had red flags in their bills for some time.

14 MME, EPE, 'Ten-Year Energy Expansion Plan 2029', Brasília: MME/EPE (2020), p. 286, at, (last accessed on 22 April 2020).

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