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 (63 per cent of the installed capacity, excluding small plants), while thermal power plants have an important role in complementing the mix and assuring security of supply (17 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 more recently been encouraged by net metering policies, 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 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:
- the National Council on Energy Policy, which isthe presidential cabinet for energy policy affairs created by Law 9,478/1997; and
- 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 (former concessions fall within this regime), 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 sizze 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 SHPP 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.
In respect of new projects, plants subject to an authorisation regime may choose to participate in a power auction to be granted the correspondent authorisation and sell electricity on the regulated market.4 They may also decide to sell their production on the free market, but will first need to undergo an authorisation process with ANEEL to operate the power plant and freely trade the plant's output.
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 in light of 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.5 Former concessions are also operated under public service regimes.
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 source||Installed capacity||Regulatory licence||Regimes|
|Hydropower||Greater than 50MW||Concession for use of public asset (preceded by a public auction)||Independent power producer|
|Greater than 5MW but not greater than 50MW (certain plants may be characterised as SHPPs)||Authorisation||Independent power producer or self-producer|
|Up to 5MW||Communication|
|Thermal power plants and renewable energy (except hydropower)||Greater than 5MW||Authorisation||Independent power producer or self-producer|
|Up to 5MW||Communication|
There are currently discussions on whether private investors are allowed to 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 or even controllers (subject to a public procurement).
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 in to purchasing energy from only one intermediary: the local distribution companies to which they are connected. Although there is a special regulation for those that use between 500kW and 3MW, they can choose to buy energy from incentivised sources or SHPPs.
In addition, in light of 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.
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:
- foreign companies shall organise a special purpose company under Brazilian law to have the regulatory licence granted; and
- 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, 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.
In addition, there are specific restrictions for the organisation of power companies in the economic group. Unbundling, adopted by the sector since its restructuring in the 1990s and extended further as part of the 2004 regulatory reform, restricted the activities of distribution companies in the regulated market, limiting their participation in other activities within the supply chain. 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 interest6 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'7 – 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 as 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 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 generation, transmission and distribution activities be undertaken by separate legal entities, with specific restrictions on the corporate structure of their economic groups (see Section II.iii).
The 2004 regulatory reform imposed restrictions on the distribution companies within the interconnected system by forbidding them to undertake any activities in connection with:
- sale to non-captive consumers;
- direct or indirect participation in other companies, except for the funding, implementation and management of financial funds for the provision of service; and
- activities unrelated to the purpose of the concession, except for the instances provided by law or in the concession contract.
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 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 respetct 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.
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 by transportation.
ANEEL and the National Telecommunications Agency (ANATEL) collaborated to issue regulations on the reference price applicable to infrastructure sharing (Joint Resolution 04/2014), following several disputes on the subject.
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; a productivity factor, known as the X factor, is also applicable. 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.
Between the periodic reviews, rates are adjusted annually for inflation (from which the X factor is subtracted). 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.
i Development of energy markets
The 2004 restructuring process that established 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 market. 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). 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 types of auctions within the regulated market:
- new-project auctions, conducted to promote power generation expansion sufficiently in advance to enable plant construction, to meet growth in market consumption;
- existing project auctions, conducted to contract power produced by existing projects, to reduce the financial risks for distribution companies in their demand projections; and
- backup energy auctions, conducted to increase security of power supply.
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), which need prior technical qualification before the EPE to be entitled to participate in the auctions. There are also auctions for existing projects, in which generation companies with projects in operation may sell power within the regulated market, and renewable energy auctions, which can be launched for either new or existing projects. Finally, backup energy auctions relate to contracted power originated from SHPPs, wind and biomass plants. 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.
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. Free consumers, who may choose their power generation supplier, are those whose demand is currently higher than 2MW. According to an Ordinance issued by the MME in December 2018, as amended in 2019, this 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 consume the same amount as purchased under PPAs.
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:
- 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;8 and
- subject to penalties imposed by the CCEE.9
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.10 This calculation is very important as it sets the limit on the power available for sale (originating from the plants' own power generation).11
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 a number of 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, as a result 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.12
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. Particularly, 2019 was intended to be the year in which ANEEL would change its regulation on distributed energy and net metering. There were expectations that higher tariffs would apply to consumers connecting a power generation facility to the grid after the issuance of the revised regulation, but these discussions were postponed to 2020. Nevertheless, the expected changes caused a race among consumers such that units with distributed energy jumped from 58,000 at the end of 2018 to 176,000 at the end of 2019 and installed capacity jumped from 0.7GW to 2.2GW, mostly from solar sources.
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 recent information made available in the 2020–2029 Energy Plan,13 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 may change in the future as the sources become more competitive, as anticipated in the discussions about a bill of law to implement certain changes in the regulations.
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 local incentives granted by 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.14 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. ANEEL believes that this change 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. In addition to regulations on the band pricing scheme, ANEEL has established a net metering policy for renewable micro and mini distributed generation,15 and has issued regulations imposing a future obligation on distribution companies to instal electronic metering for Group B16 consumers. The aim of these measures, taken to allow integration between power supply and communications technology, was to improve the quality of service provision and to reduce operational costs and technical losses in power supply.17
The year in review
There was been a cautious resumption of growth in the Brazilian electricity sector. In 2019, ANEEL carried out several successful generation and transmission auctions, delineated operation strategies to modernise the Brazilian electricity grid, issued important regulatory resolutions and incorporated changes to the current regulation.
Regarding the revision of the current net metering regulations, ANEEL launched a series of public consultations and public hearings to discuss concepts, issue a regulatory impact assessment and potential changes in the regulations. The aim of the revision is to rebalance the costs generated by the current system of net metering that are borne by other consumers and distribution companies and may increase tariffs paid by net metering users in the future. ANEEL's current proposal is to respect the financial expectations of those connecting net metering systems before 2020, which may be subject to lower tariffs than those connecting after 2019. Recently, Jair Bolsonaro, Brazil's elected president, has spoken out against ANEEL's proposal to reduce incentives with regard to net metering. The last public hearing took place in December 2019 and the outcome of the proposal is not yet known.
During the period in review, one transmission auction was successfully conducted, marking the entrance and consolidation of foreign investors. The bid occurred in December 2019 and contracted 2,467km of transmission lines and 7,791MVA in substation capacity in 11 states, with an expected investment of 4.18 billion reais.
Generation auctions were also successfully conducted in 2019:
- in December, separate bids contracted:
- 4,888GWh from existing power ventures (an estimated investment of 838 billion reais); and
- 5,08GWh from existing power ventures (an estimated investment of 80 billion reais);
Mergers and acquisitions transactions have also been successfully carried out during the year, including the following:
- the acquisition, by Engie, of a transmission project named Projeto Novo Estado, formerly owned by the transmission company Sterlite, for about 410 million reais;
- the acquisition, by Vinci Partners, of a transmission project named Projeto Arcoverde, formerly owned by the transmission company Sterlite, for about 141 million reais;
- the acquisition, by Energía Bogotá Group and Red Eléctrica Internacional, of the transmission company Argo Energia, for about 3.5 billion reais;
- the acquisition, by Enel Green Power, of wind farms totalling 540MW of installed capacity, formerly owned by Enel Green Power Brasil, for about 4.1 billion reais;
- the acquisition, by Vale, of all the energy produced from the Folha Larga Sul wind farm (151.2MW/BA), with the option to purchase the entire project after it went into operation in 2020;
- Canada Pension Plan Investment Board entered the national holding Equatorial Energia, with the purchase of 5 per cent of the common shares traded on the Brazilian B3 exchange;
- the acquisition, by Mitsui, of 17 per cent of Órigo Energia's share capital;
- the acquisition, by the transmission company Taesa, of two Âmbar Energia projects located in the states of Piauí and Bahia for about 753 million reais; and
- the acquisition, by Actis, of a wind farm formerly owned by EDP Renováveis, for about 650 million reais.
Conclusions and outlook
Activity on the Brazilian electricity market continued to be eventful in 2019. The sector has been trying to adjust to the new economic and political situations, 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):
|2020||LEE A-4||30 April 2020|
|LEE A-5||30 April 2020|
|LEN A-4||28 May 2020|
|LEN A-6||24 September 2020|
|LEE A-1 e A-2||4 December 2020|
|2021||LEN A-4||29 April 2021|
|LEN A-6||30 September 2021|
|LEE A-1 e A-2||3 December 2021|
Certain large companies are likely to be privatised in the coming years, such as Eletrobrás, Cemig, Copasa and CEB.
In addition, net metering is expected to continue growing after reaching the level of 2.2GW of installed capacity in 2019.
Furthermore, the expansion of the free market is already set forth in the regulations, with reduced demand requirements entering into force in January 2021 (to 1.5MW), 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, net metering generation to 50 billion reais, and another 104 billion reais in power transmission and substations.18 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 Lucas José Russo for his 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 Banco de Informações de Geração, at www.aneel.gov.br/aplicacoes/capacidadebrasil/capacidadebrasil.cfm (last accessed on 22 April 2020).
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 In this case, the auction usually requires that a minimum percentage be allocated to the regulated market.
5 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 are allowed to sell the unused portion of their own output under the conditions set forth by rules and regulations.
6 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.
7 Art. 5º (IV) of ANEEL Resolution 484/12.
8 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.
9 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.
10 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.
11 Although in the regulated market the assured capacity represents the limit available for sale, participants in the free market are able to sell an amount above the assured capacity if they have executed PPAs to cover the total amount sold.
12 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.
13 Ministry of Mines and Energy [MME], Energy Research Company [EPE], 'Ten-Year Energy Expansion Plan 2029', Brasília: MME/EPE (2020), p. 13, at https://www.epe.gov.br/sites-pt/publicacoes-dados-abertos/publicacoes/Documents/PDE%202029.pdf (last accessed on 22 April 2020).
14 Green, yellow and red flags indicate lower, medium and higher generation costs. As a result of the recent water shortages, the Operador Nacional do Sistemo 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.
15 Under this policy, the possible excess of a consumer's production is exported into the grid and assigned to the distribution company, and thus may be compensated with credits in the subsequent billing periods, under the conditions set forth by regulations.
16 Residential, rural and other classes, except for low income consumers and streetlight facilities.
17 ANEEL, 'ANEEL regulamenta medidores eletrônicos' (8 August 2012), at www2.aneel.gov.br/aplicacoes/noticias/Output_Noticias.cfm?Identidade=5903&id_area=90 (last accessed on 11 May 2020).
18 MME, EPE, 'Ten-Year Energy Expansion Plan 2029', Brasília: MME/EPE (2020), p. 286, at http://www.epe.gov.br/sites-pt/publicacoes-dados-abertos/publicacoes/Documents/PDE%202029.pdf, (last accessed on 22 April 2020).