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Market Overview

Background

Until the middle of the nineties, the electricity sector was largely made up of state-owned companies operating both in the activities of electricity generation and also transmission and distribution. During this period, resources required for building power plants, transmission lines and distribution systems were publicly funded, feeding through to an investment shortfall in the electricity sector.

The increase in demand for energy due to strong economic growth obliged a change in the model adopted  in order to ramp up power supplies.

The federal government set about reforming the sector. It enacted rules for allowing the participation of private initiative in the electricity generation segment and introduced competition into the trading of energy with the creation of the free consumer concept. In 1993, tariff equalization was extinguished with power purchasing agreements between generators and distributors being created, paving the way to privatization.

Electricity sector restructuring and privatization began during the first Cardoso administration (1995-1998) with the enactment of the concessions law. This restructuring changed the profile of the electric energy companies, dividing them according to operational segments, namely: generation, transmission and distribution.  Each segment was given its own regulatory framework.
This model required a regulator, the National Electric Energy Agency (ANEEL); a national grid operator, the National Electrical System Operator (ONS), and a suitable environment for the purchase and sale of electric energy, the Wholesale Electric Energy Market (MAE), now the Electric Energy Trading Board (CCEE).

Early on in the first decade of the new century, the electricity sector experienced a grave supply shortage, entailing energy rationing in Brazil for a period. This event culminated in the adoption of regulatory changes for ensuring continuity of electricity supplies, a balance between supply and demand, tariff moderateness and social inclusion.

In 2001, with the energy crisis, the government was obliged to introduce emergency rationing programs in the Southeast, Central/Western and the Northeast regions, a reflection of insufficient investment, increased demand and lower reservoir levels. The crisis also increased the urgency for structural changes laid out in the New Brazilian Electricity Model and implemented from 2004.

The new rules redefined the role of the government and the sector regulatory agencies. New institutional agents were put in place: the Energy Research Company (Empresa de Pesquisa Energética - EPE), responsible for long-term planning for the sector; the Electric Energy Sector Monitoring Committee (CMSE) for permanently evaluating the security of electric energy supplies; and the Electric Energy Trading Board (CCEE) which replaced the Wholesale Electric Energy Market (MAE).

In the new model, generators, independent producers and commercializing companies began to operate in the regulated and free contracting environment. The system for the purchase and sale of energy now incorporated the free market conducted through agreements freely negotiated between agents (not distributors) and free consumers, and the regulated market for the sale of energy through public auctions promoted by ANEEL or CCEE. The commercialization of electric energy by the distribution concessionaires now became restricted to the regulated contracting environment.

In the ensuring years, the expected transformation of the electricity sector gathered pace set against the background of the new macroeconomic scenario,  the reduction of Brazil country risk and government policies for stimulating the economy. All this benefited the companies in the electric sector. There was a wave of mergers and acquisitions, with an acceleration in the pace of deverticalization set in motion with the introduction of the new model for the sector.

Presidential Provisional Measure 579 (MP) was published in September 2012 covering the system to be adopted for renewal of the electric energy generation, transmission and distribution concessions, the reduction in sector charges and tariff moderateness. The MP extinguished charges relating to the Fuel Consumption Account (CCC) and the Global Reversal Reserve (RGR). The Energy Development Account (CDE) charge was reduced by 75%. Criteria were also established for extending the concessions. The treatment of these concessions endeavors to capture the amortization and depreciation of the investments in generation projects and in transmission and distribution installations to the benefit of tariff moderateness.

The Federal Government is estimating an across-the-board average reduction of 20% in energy tariffs to the final consumer (16.2% in the tariff to residential consumers and up to 28% in tariffs to industrial consumers supplied by the distributors). The publication of this MP has triggered uncertainty in the market. However, the new rules on the renewal of the concessions will not directly affect EDP Energias do Brasil, since the first maturities of its generation concessions only occur in 2025. Furthermore, the automatic extension of the concessions under the same terms as currently prevail was never an assumption built into the company’s investment evaluations.

General Characteristics

The Brazilian generator complex is largely hydroelectric in spite of the growing participation  of thermal plants and energy from renewable sources.

Brazil has the third largest hydroelectric potential in the world with approximately 248 GW, about 43% of this potential, having been harnessed. The Ten Year Expansion Plan approved by the Ministry of Mines and Energy in 2017 states that the country’s installed generation capacity is expected to increase to 212.5 GW by 2026, of which 110.5 GW (52.0%) will correspond to hydro generation, 23.3 GW (10.9%) to thermal generation, 3.4 GW (1.6%) to nuclear generation, 63 GW (29.7%) to other renewable sources and 12.2 GW (5.7%) to indicative alternative (that may include open cycle thermoelectric plants, reversible plants, additional hydroelectric power generation, batteries or demand management).  (Source: EPE – Ten-year plan 2017-2026).

In 2017, electricity consumption in Brazil amounted to 463,948 GWh, 58.1% of which being consumed by the Southeast/Midwest Region. Industrial Class consumption, characterized by large heavy-duty consumers, principally in the steel, metallurgical and pulp and paper areas, totaled 165,883 GWh, corresponding to 35.8% of total electric energy consumption, increase of 1.3% when compared to 2016. Residential class consumption totaled 133,904 GWh, 28.9% of the total, per capita consumption per month being 157 kWh.

(Source: Monthy Research - EPE - January  2018)

Generation

The physical characteristics of Brazil, notably its territorial extension and abundance of water, have been critical to the installation of a predominantly hydraulic driven generator complex.

Electricity power plants are subject to concession, authorization or registration according to the classification based on type of unit, capacity to be installed and end-use of the energy. Based on energy usage, plants may be classified as:

  • Producers for which the concession grant specifies that the energy shall be delivered to the public  utility service;
  • Independent producers (which take on commercialization risks with distributors or directly with free consumers); and
  • Self-producers (production of energy for own consumption, any excess being commercialized against authorization).

The generators may sell their energy to the distributors through public auctions conducted by ANEEL, the sale being implemented by CCEE. In the Free Contracting Environment, generators may sell their energy at freely negotiated prices to commercializing companies, distributers with a market of less than 500 GWh/year and Free Consumers.

Energy Reallocation Mechanism – MRE

MRE operates through a process which firstly examines the capacity of the plants in the same region to meet assured energy requirements and then the sharing of excess generation among the different regions.

Optimized Energy

Generators, members of the MRE, which have produced energy in excess of assured energy levels are compensated for the variable Operation and Maintenance costs - O&M and costs with the payment of royalties for water usage. MRE generators which have failed to generate their stipulated levels of assured energy have to pay Operation and Maintenance costs - O&M and water usage royalties to the generators which have produced more than their respective levels of assured energy during the same period.

Secondary Energy

The total energy in the MRE remaining after the allocation for coverage of generators which have failed to produce their respective assured energy is known has “secondary energy”. Secondary energy is allocated in accordance with the levels of assured energy of all the members of the MRE.

Generation Scaling Factor ( GSF)

In periods of surplus hydroelectric generation in the country, the Energy Reallocation Mechanism (MRE) distributes earnings to participating plants of this system, called as secondary energy, and the opposite occurs in periods of hydrological shortage that the generation deficit is deducted from the physics warranty of plants causing revenue losses.

The GSF - Generation Scalling Factor - is a factor that relates Hydro Generation and Hydro Physics Guarantee of MRE participants. When the system generation is less than the physical guarantee, this factor reduces the energy available for sale generator. If the reduced physical guarantee of the GSF is less than the necessary to cover sales contracts, there will be compulsory purchase in the spot market of the CCEE valued at the PLD.

Given the unfavorable impact of the GSF on the generators, in May 2015, ANEEL held Public Hearing 032/2015. The outcome was Normative Resolution 684/2015 establishing the conditions for the renegotiation of hydrological risk of those genrators comprising the Energy Reallocation Mechanism – MRE against payment of a Risk Premium, retoractive to January 2015.

The mechanism is being implemented as from January 2015, expenses incurred by the generator above the renegotiated amount  not being reimbursed but rather compensated.

For generators selling through the Regulated Contracted Environment (ACR), GSF losses will be passed on in full to the Tariff Flag Resources Account against payment of a Risk Premium. The generators’ GSF losses in 2015 will be compensated through exemption from the risk premium payment as from January 2016 until accumulatred losses are cleared. The Risk premium varies between R$ 0.75 and R$ 12.75, depending on the percentage of risk which the generator plans to renegotiate: from 89% to 100%.

The Risk Premium for sales within the scope of the Free Contracting Environment (ACL) varies from R$ 10.50 to R$ 23.10, contingent on the amount of Reserve Energy acquired from the system. The reimbursement of GSF losses for 2015 is made exclusively through the extension of the term of the generation agent’s  concession contract. Renegotiation in this case does not exclude the generator from GSF-related costs.

Following due consideration, EDP Energias do Brasil has decidd to adhere to the renegotiation of the hydrological risk in the Regulated Contracting Environment, although not in the case of the Free Contracting Environment. By accepting the proposal  and in line with the new renegotiation rules, the companies have agreed to cancel all injunctions filed on their behalf by The Brazilian Association of Independent Power Generators – APINE, which had been instrumental in allowing generators to avoid GSF payments since May 2015. In practice, no cash disbursements for amounts due under market rules for the GSF had been made by those taking out preliminary injunctions up to December 2015.

To check the plants approved,  visit our Notice to the Market:

Distribution

Until the middle of the nineties, the Brazilian distribution segment was operated almost exclusively by state-owned companies. Following a series of tender bids, the segment is now highly fragmented, with 56 distributors operating in Brazil (70% private sector and 30% privatized companies).

Currently, the distributors may only offer services to their captive clients within their respective concession areas under conditions and tariffs regulated by ANEEL. As a result, should a distributor decide to practice some form of discount to the value of the regulated tariff, then the principal of isonomy must be taken into account.

In 2017, the electric energy distribution segment in Brazil took 463,948 GWh from the generators, of which 29% for residential consumers, 36% for industrial consumers, 19% for commercial consumers and 16% for other consumer types. As of December 31, 2017, the total number of residential customers was approximately 71 million.

Source: Electric Energy Market Monthly Report - January/2018 published by the Empresa de Pesquisa Energética (EPE).

Electric Energy Distribution

Tariffs The tariff control mechanism was historically a way of encouraging the substitution of other forms of energy for hydroelectricity. However, high interest rates and the use of tariffs as an instrument for controlling inflation, introduced in the eighties, reduced the incentive to invest in generation, thus increasing the possibility of rationing.

Following the creation of ANEEL, in 1997, the agency began to regulate the tariffs practiced by the distributors based on the concession agreement which establishes, among others, the tariffs to be charged and the respective criteria for readjustment/revision. Under this regulatory environment, tariffs are differentiated by consumer type (consumption class) and supply tension (group/subgroup).

The structure of the distribution  tariff is made up of the costs of energy purchase, distribution, transmission, taxes, sector and social charges. It is worth mentioning that the distributor is the agent responsible for collecting and passing on costs on behalf of all the sectors.

Tariff Readjustments and Revisions

Electric energy tariffs (use of network and retail supply) are readjusted annually by ANEEL (periodic annual readjustment), reviewed periodically (periodic tariff revision) every 3, 4 or 5  years depending on the concession agreement. Values may also be reviewed on an extraordinary basis (extraordinary tariff revision).

ANEEL divides distributor revenue into two parcels corresponding to the following costs: (i) non-manageable costs known as Parcel A costs; and (ii) manageable costs or Parcel B costs.

Parcel A costs include the following items:

  • acquisition costs of electric energy obtained through public auctions held by ANEEL;
  • acquisition costs of electric energy from Itaipu Binacional;
  • acquisition costs of electric energy under Bilateral Agreements;
  • costs relating to connection charges and use of transmission and distribution systems and sector charges.

Parcel B incorporates the costs over which the concessionaires have control such as the costs of capital and operational and maintenance costs. Operational costs are the most significant. Upon each readjustment, Parcel B is obtained as result of subtracting Parcel A from total revenue recorded in the period under review - defined as the period which has elapsed between the last readjustment and the one being processed. In other words Parcel B represents a residual amount.

Tariff Flag

The Tariff Flag System came into effect on January 1, 2015. This mechanism serves to indicate the real costs of electricity generation to consumers through the division into 3 flags: green, yellow and red. The green flag indicates that the cost for generating energy is lowest and for this reason, no modification being made to energy tariffs. Conversely, the yellow and red flags represent an increase in the costs of energy generation, an additional amount being applied to the tariff. The decision as to which flag should be billed to consumers is that of the National Electricity System Operator – ONS. ANEEL ratifies the monthly amounts to be transferred to each distributor and eventual costs not covered by revenue will be considered in the subsequent tariff process.

On February 4, 2015, the Tariff Flag Resources Centralizing Account – CCRBT was established under Decree 8.401. The distributors are required to deposit resources raised from the imposition of the tariff flags to this account, which is managed by the CCEE. The resources are distributed according to consumer class and deducted in full as a charge. Subsequently, ANEEL ratifies the amounts on a monthly basis for transfer to each distributor for covering unforeseen costs in the tariffs stemming from surcharges with respect to the Energy Safety System Charge- ESS, thermal dispatch, hydrological risk, Itaipu quotas, exposure to the short-term market and excess of the Reserve Energy Account – CONER. These represent amounts to be reduced from energy purchased for resale.

In 2016, the values of the yellow and red tariff flags suffered changes: the red tariff flag started to have two thresholds, with an extra charge of R$ 3.00 and R$ 4.50 for each 100 kWh consumed, and the yellow tariff flag an extra charge from R$ 2.50 to R$ 1.50 for each 100 kWh consumed. 

In 2017, the values of the yellow and red tariff flags suffered changes: the red tariff flag started to have two thresholds, with an extra charge of R$ 3.00 and R$ 5.00 for each 100 kWh consumed, and the yellow tariff flag an extra charge of R$ 1.00 for each 100 kWh consumed. 

 

Commercialization

Commercialization agents operate basically in three ways: (i) trader – purchase and sale of electric energy in their own name in free and organized markets, bearing all market risks; (ii) broker – intermediates negotiations and the contacts between the seller and the purchaser, using their knowledge of the market for generating new business; and (iii) Consultant – undertakes prospection and feasibility studies as well as rendering services in the free contracting environment on the CCEE.

Transmission

The Brazilian transmission system with nominal tension of more than 230 kV is known as the Basic Transmission Network. The role of the Basic Network is to ensure the integration between remote sources of energy and the load centers, represented by terminal substations for serving distributors or direct serving of major clients.

In addition, the Basic Network is fundamental to the system’s operations, given that it integrates different hydrographic basins or different regions of the country. In this way, the network allows constant energy interchange for optimizing the operational costs of the generator complex (complementary thermal plant operations) through the substitution of high cost thermal generation for hydraulic. Brazil has approximately 125.8 thousand kilometers of Basic Transmission Network connected to SIN (National Interconnected System) – (Source: EPE – Ten-year plan 2015-2024).

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