Following some political interference in Brazil's electricity sector in the past, which temporarily weakened financial metrics across the sector, S&P Global Ratings believes the regulatory framework for the sector has substantially improved.
Brazil's Electricity Regulatory Framework At A Glance
We view the regulatory framework as the single most important factor in assessing a regulated utility's competitive position (see "Key Credit Factors for the Regulated Utilities Industry," published on Nov. 19, 2013). We view the Brazilian regulatory framework allows for a reasonable return on investments and adequate compensation for distribution and transmission activities. As a result, it's gradually aligning with more robust and politically independent frameworks we observe in the region.
|Key Credit Factors Of The Brazilian Electricity Regulatory Framework|
|Regulation has been in place since 2004 for electric utilities.|
|We consider the predictable and transparent regulatory framework as supporting credit quality of the sector players.|
|Tariffs are set annually for distribution and transmission companies, passing on inflation cost into tariffs; tariffs for distributors also incorporate intra-year costs.|
|The regulator resets tariffs for distributors every three to five years (depending on the case) by revising the regulatory weighted average cost of capital (WACC), remunerating the companies' regulatory asset base and incorporating efficiency factors.|
|The sector players are able to recover their operating and capital costs, although the full recovery of higher energy costs may be delayed. Nevertheless, the regulation assures that all of these costs are fully recovered by the end of the concessions.|
|We view Agencia Nacional de Energia Eletrica (ANEEL) as an independent regulatory body, which has operated without significant political interference from the Brazilian government over the past few years.|
|After the Bolsonaro administration took office in January 2019, we expect discussions to advance in the coming years about the energy sector's key aspects, such as hydrology risk and the potential privatization of the government-owned utility, Centrais Eletricas Brasileiras S.A. – Eletrobras.|
|Discussions between Brazil and Paraguay regarding the tariff that's part of the electricity sales of Itaipu Binacional starting in April 2023.|
ANEEL is responsible for regulating and supervising the generation, transmission, trading, and distribution segments through the following activities:
- Establishing sector-wide regulations;
- Holding auctions for new concessions;
- Supervising and inspecting the concessionaires' service quality and applying penalties;
- Defining criteria for calculating the distribution and transmission tariffs, including the ones for hydropower generation companies with concessions renewed under the Law 12,783/2013; and
- Resolving any administrative litigations between power generators and buyers.
Other supervisory bodies
- CNPE is an inter-ministerial board that advises the president to optimize the use of energy resources and assure power supplies in the country.
- MME is responsible for formulating and implementing power-related policies, which the CNPE defines. MME grants energy concessions and establishes main policies, guidelines, and regulations. MME delegates the regulation and inspection of the electricity sector to ANEEL.
- EPE is a state-owned company that develops studies and research to support the expansion and maintenance of the domestic energy industry, including oil and gas, electricity, natural gas, etc. EPE defines 10-year energy plans and revises them on an annual basis, which outline the necessary investments to meet the demand. MME uses this plan to prepare an investment plan for the sector's expansion.
- The ONS coordinates and controls generation and transmission activities. The ONS is also responsible for submitting plans for expansion of the electric grid, the National Interconnected System (Sistema Interligado Nacional in Portuguese) to MME.
- CCEE carries out wholesale transactions and commercialization of electric power in the regulated, free, and spot markets.
- CMSE is an advisory board that monitors and evaluates power supply continuity and safety, and develops proposals for the proper and safe implementation of projects, such as construction of new plants and transmission lines.
Companies in the Brazilian electricity sector
While the state-owned companies—at the federal and state levels—dominate the transmission segment, private-sector companies are the main players in the generation and distribution segments.
Hydropower accounts for most of Brazil's electricity output. Hydropower accounts for about 65% of Brazil's total installed generating capacity, compared with the global average of below 20%. Therefore, hydrology is a key factor to monitor because it influences system-wide energy production and costs, particularly because the complementary power sources, such as thermal, are more costly. Since the 2001 power rationing, the country has been making investments to diversify its energy matrix, and thermal power now represents about 20% of the installed capacity, which is bolstering the system's reliability. Wind generation has also grown exponentially during the past decade, and now represents 10% of the matrix. Finally, nuclear energy only produces 2 gigawatt (GW) of the country's total power through the Angra I and Angra II plants. A third plant--Angra III--has been under construction since 1984, and likely to add 1,350 megawatt (MW) by 2026. Eletrobras is the largest player in the generation segment, because it accounts for almost 20% of the country's installed capacity (down from 28% in 2010), excluding its 50% stake in Itaipu. We expect Eletrobras's share of this segment to continue gradually falling, as more private players have won bids in the electricity auctions during the past 10 years.
Electricity transmission. As of February 2019, the Brazilian electric system had 146,644 km of transmission lines. We expect 500 kilovolt (kV) lines to become more relevant in the system in terms of extension, as companies are investing in reinforcement works, which indicates an optimization of the existing resources.
|Transmission Lines In Brazil|
|Tension (kV)||Length (km)||% of total|
Eletrobras is also the largest single transmission operator, with about 70,000 km of the transmission lines (53,790 km in 2010), equivalent to about 47% of the national grid. The remaining portion is distributed among private players.
Electricity distribution. After the 2018 privatization of the distribution companies formerly owned by Eletrobras, only a few players currently operating in the sector are still state controlled. Distribution companies operates under 30-year contracts, which could be renewed for additional 30 years upon ANEEL approval. Only 5% out of about 60 concessions and permission contracts mature prior to 2026.
Brazilian legislation forbids vertical integration in the sector, i.e. ownership of distribution and generation concessions under the same entity. Still, we note the development of large integrated groups, which own various concessions under an umbrella holding level, adhering to all regulatory requirements that limit commingling.
|Rated Entities In Brazil|
|Company||Segments||Business risk||Financial risk||Liquidity||Other active modifiers||Subsidiary status/government support||SACP||Ratings|
Ampla Energia e Servicos S.A
|Distribution||Fair||Aggressive||Adequate||--||Enel Americas (highly strategic)||bb-||BB+/Stable/--; brAAA/Stable/--|
Companhia Energetica do Ceara - Coelce
|Distribution||Satisfactory||Intermediate||Adequate||--||Enel Americas (highly strategic)||--||brAAA/Stable/brA-1+|
Companhia Paulista de Forca e Luz
Companhia Piratininga de Forca e Luz
|Rio Grande Energia S.A.||Distribution||Satisfactory||Significant||Adequate||--||CPFL (core)||--||brAAA/Stable/--|
EDP Espirito Santo Distribuicao de Energia S.A.
|Distribution||Satisfactory||Significant||Adequate||--||EDP (strategically important)||bb+||BB-/Stable/--; brAAA/Stable/--|
EDP Sao Paulo Distribuicao de Energia S.A.
|Distribution||Satisfactory||Significant||Adequate||--||EDP (strategically important)||--||brAAA/Stable/--|
Energisa Paraiba-Distribuidora de Energia S.A.
|Distribution||Satisfactory||Significant||Adequate||--||Energisa (core)||bb+||BB-/Stable/--; brAAA/Stable/--|
Energisa Sergipe-Distribuidora de Energia S.A.
|Distribution||Satisfactory||Significant||Adequate||--||Energisa (core)||bb+||BB-/Stable/--; brAAA/Stable/--|
Companhia de Eletricidade do Estado da Bahia
|Distribution||Satisfactory||Aggressive||Adequate||--||Neoenergia (core)||bb||BB-/Stable/--; brAAA/Stable/--|
Companhia Energetica de Pernambuco (CELPE)
|Distribution||Satisfactory||Aggressive||Adequate||--||Neoenergia (core)||bb||BB-/Stable/--; brAAA/Stable/--|
Companhia Energetica do Rio Grande do Norte
|Distribution||Satisfactory||Aggressive||Adequate||--||Neoenergia (core)||bb||BB-/Stable/--; brAAA/Stable/--|
Elektro Redes S.A.
Centrais Eletricas do Para S.A.
Light Servicos de Eletricidade S.A.
|Distribution||Fair||Significant||Adequate||Comparable rating analysis: negative||--||--||brAA+/Stable/brA-1+|
CEMIG Distribuicao S.A.
|Distribution||Satisfactory||Highly leveraged||Less than adequate||Comparable rating analysis: negative||CEMIG (core)||b||B/Stable/--; brA+/Stable/--|
Transmissora Alianca de Energia Eletrica S.A.
Integração Transmissora de Energia S.A.
|Transmission||Fair||Significant||Adequate||--||Equatorial (highly strategic)||--||brAAA/Stable/--|
Cachoeira Paulista Transmissora de Energia S.A.*
Celeo Redes Transmissao de Energia S.A.*
Iracema Transmissora de Energia S.A.*
Jauru Transmissora de Energia S.A.*
Norte Brasil Transmissora de Energia S.A.*
Rio Paranapanema Energia S.A
|Generation||Satisfactory||Minimal||Strong||Comparable rating analysis: negative||China Three Gorges (nonstrategic)||bbb+||BB/Stable/--; brAAA/Stable/--|
CESP-Companhia Energetica de Sao Paulo
|Generation||Satisfactory||Significant||Adequate||--||Federative Republic of Brazil (extremely high likelihood of support)||--||brAAA/Stable/--|
Santa Vitoria do Palmar Holding S.A.*
Geradora Eolica Bons Ventos da Serra I S.A.*
Chapada do Piaui I Holding S.A.*
|Distribution and transmission||Satisfactory||Significant||Adequate||--||--||bb+||BB-/Stable/--; brAAA/Stable/--|
CPFL Energia S.A.
|Distribution, generation, transmission, and trading||Satisfactory||Significant||Adequate||--||State Grid Corporation of China (strategically important)||--||brAAA/Stable/--|
|Distribution, generation, transmission, and trading||Satisfactory||Aggressive||Adequate||--||Iberdrola (strategically important)||bb||BB-/Stable/--; brAAA/Stable/--|
Equatorial Energia S.A.
|Distribution, and transmission||Fair||Significant||Adequate||--||--||--||brAAA/Stable/--|
Eletrobras-Centrais Eletricas Brasileiras S.A.
|Generation and transmission||Satisfactory||Highly leveraged||Less than adequate||Comparable rating analysis: positive||Federative Republic of Brazil (almost certain likelihood of support)||b+||BB-/Stable/--; brAAA/Stable/brA-1+|
Companhia Energetica de Minas Gerais
|Distribution, generation, and transmission||Satisfactory||Highly leveraged||Less than adequate||--||State of Minas Gerais (Moderate likelihood of support)||b||B/Stable/--; brA+/Stable/--|
CEMIG Geracao e Transmissao S.A.
|Generation, and transmission||Satisfactory||Highly leveraged||Less than adequate||--||CEMIG (core)||b||B/Stable/--; brA+/Stable/--|
|*Analyzed under our project finance criteria.|
When assessing the regulatory stability, we focus on the transparency of the key components of the tariff setting, the framework's predictability, and its consistency of over time.
The current regulatory framework, which has been in place for 15 years, hasn't undergone significant changes during that period. ANEEL is the Ministry of Energy's vehicle for policy implementation. In this role, ANEEL has:
- Pursues tariff modality under the terms of the concession contracts;
- Helps ensure that contracts are balanced from financial and economic perspectives; and
- Ensures that investments are properly remunerated.
In terms of remit, ANEEL has greater influence over regulated utilities, distribution, and transmission companies. Its influence over generation companies is smaller because they can sell electricity not only in the regulated market, but also in the free and spot markets.
Tariff Setting Procedures And Design
When assessing the tariff-setting procedures and design of a regulatory framework, we focus on the recoverability of all operating and capital costs in full, the balance of interests and concerns of all stakeholders, and whether incentives are realistic. In Brazil tariffs are set in order to remunerate the investments made in the concession area. MME assures the right of the companies to receive, until the end of the concession, the whole remuneration for the investments made and any costs not fully recovered through tariffs. As a result, we believe that Brazil's regulatory framework for the electricity sector supports operators' credit quality.
Therefore, our current view of the regulatory advantage for Brazil's electric utilities is adequate, which is in the middle of our range. In comparison, we view Chile's framework as the strongest and Argentina's as the weakest. We consider that the regulatory framework fosters the sector's stability. Distribution companies operate under regulated tariffs that incorporate the manageable and non-manageable costs, such as operating expenses, the currency depreciation, and capital returns. Power generators mitigate cash flow volatility through long-term power sale contracts to distribution companies and large users. Large hydropower generators partly offset hydrology risk through the energy reallocation mechanism. Finally, transmission concessions receive fixed tariffs only depending on availability payments.
Given that the distribution companies currently operate under a model of pass-through costs, along with the remuneration of their investments, they have a tariff reset every three to five years (depending on the concession contract). Tariff readjustments allow the companies to pass through the incurred electricity costs and G&A-related expenses, which are pegged to inflation, to the clients. Tariff reviews incorporate efficiency gains during the cycle, which are shared with the customers. In each cycle, the regulator sets a new WACC to remunerate the investments during the concession. Distribution companies also have the right to request an extraordinary tariff review, in order to recover the financial and economic rebalancing of the concession contract.
Regulatory Independence And Insulation
When we assess regulatory independence and insulation, we look at the market framework and how the law preserves and separates the regulator's powers, as well as any risk of political intervention.
We believe that ANEEL currently enjoys considerable political independence. In 2013, the federal government enacted Law 12,783, aiming to reduce electricity bills through the renewal of concessions for generation and transmission entities maturing between 2015 and 2017. Despite this political interference, the concession renewals were voluntary and ANEEL didn't penalize those companies that refused to do so.
These factors support our current valuation of the regulatory framework advantage as adequate, which is in the middle of our range. We view positively the government's new agenda that aims to reduce bureaucracy in the infrastructure sector and a an improvement in the business environment in the country. Therefore, we would likely revise upward our assessment of the framework following changes to enhance administrative continuity over political cycles. This is the main factor behind the higher assessment of the Chilean regulatory framework, which we assess as strong/adequate. (Please refer to the article "Regulatory Support Is Powering Latin America's Utilities," published March 8, 2019). We could revise our assessment of Brazil's framework downward if we perceive:
- Lesser regulatory independence or instances of political interference;
- Any substantial changes in regulation that are likely to decrease transparency, consistency, and timely recovery of costs.
- A sharp rise in country or sovereign risks that could erode the operators' financial compensation.
Unconventional renewable electricity generation has been gradually introduced into the matrix, with wind power's share of the system rising from zero to 10%. The latest hydro plants were built with limited reservoirs, in order to comply with stricter environmental laws. This trend increases price volatility in the system, because unconventional renewable and runoff the river hydro plants have an intermittent pattern of operations. As such, we believe that the system is becoming gradually more dependent on the hydrology regime, which has been less predictable over the last years. In this regard, we'll continue to monitor hydrology conditions in Brazil (reservoir levels, in particular), given that periods of abundant rain or severe drought can have an acute effect on electricity spot prices.
Despite spot-price volatility linked to intermittent nature of unconventional renewable sources, the new energy auctions--led by wind and solar projects--have shown low-energy prices, following aggressive bids from new market participants. Auctions for new solar and wind capacity totaling almost 3GW was completed between December 2017 and April 2018 at about $30 per MWh. We believe the energy price for unconventional sources may have reached its bottom, as seen in the June 2019 auction for only 200 MW of solar capacity at $17 per MWh and 100 MW of wind at $21 per MWh, which is relatively small for the size of the country's expansion plan. We believe prices below $30 per MWh are aggressive from a credit perspective, because there's a small cushion to absorb the resource risk, operating costs, and management risk during the life of the unconventional renewable asset. On the other hand, in the long run, lower energy prices should benefit residential consumers and improve industry competitiveness.
Another factor that we will be monitoring will be the negotiations between Brazil and Paraguay throughout the next years on the terms and conditions for Itaipu's electricity sales starting in April 2023. Currently, the entity's tariffs incorporate all of its expenses and its debt service. Given that all of Itaipu's debt matures on that date, there could be a review of the tariffs for the distribution companies that Itaipu supplies, and the negotiations related to the portion of electricity that Paraguay sells to Brazil, which consumes almost 90% of Itaipu's output.
Annex I: Tariff-Setting Mechanism
Generation companies can sell electricity either in the regulated, free, or spot markets. Regulated market contracts are reached during energy auctions sponsored by ANEEL. Free market contracts follow bilateral negotiations between generators and large clients (either trading companies or users that consumes at least 3,000 kilowatts [kW] on a monthly basis), usually with one- to five-year tenors. Spot market prices are mostly influenced by hydrological conditions, the likely electricity demand, and fuel prices. Nevertheless, ANEEL sets the spot price band annually (currently minimum of R$42.35 per megawatt hour [MWh] and maximum of R$513.89/MWh).
For generation companies that sell electricity in the regulated market, there are two types of contracts under ANEEL's scope:
- Contracts through a public auction, where existing or new assets offer their output to distributors. ANEEL establishes a ceiling price, and depending on the future demand of the distribution companies and the amount of electricity available, prices could be at or below the ceiling.
- Electricity quotas. In Brazil, three types of assets sell their output throughout electricity quotas: hydro power generators that renewed their concessions under Law 12,783, Itaipu Binacional, and the Angra I and II nuclear plants.
We believe that the auction contracts, once prices are determined in the bidding processes, are less subject to ANEEL's discretion, because they will be only adjusted to inflation on an annual basis until their maturity.
Under the quotas contracts, ANEEL establishes an annual generation revenue (Receita Anual de Geração – RAG), paid on a monthly basis, in order to cover generators' operating and maintenance costs, plus the remuneration of any investment needed to maintain proper operations. The RAG is annually adjusted to inflation every July, and subject to a tariff reset every five years. For the 2018-2019 cycle, average RAG of the 69 hydro plants operating under this model is R$101.18 per MWh, including taxes.
Itaipu's rates follow the guidelines established in the treaty between Brazil and Paraguay that governs the hydro plant. The main goal of the tariff is to assure that all operating and capital costs are fully covered, including the amortization of debt raised to finance the construction of Itaipu. Given that rates are set in dollars, the distribution companies in Brazil's southern, southeastern, and midwestern regions that are required to purchase electricity from Itaipu, can face higher working capital swings due to intra-year exchange rate variations, whereas their tariff adjustment occurs once a year. For 2019, Itaipu's rates are at $27.71 per kW.
ANEEL determines the tariffs. We view the tariff-setting mechanism as supportive from a credit perspective, given its transparent process.
The tariff structure for the distribution companies consists of the following factors:
- Parcel A is related to costs that are not manageable by the distribution companies:
- Cost of energy purchased: Includes energy purchased from power generators that were allocated through public auctions, any bilateral purchase contracts prior to the 2004 regulations, Itaipu's quotas, nuclear energy output quotas, and quotas provided by hydro plants that renewed their concessions under Law 12,783.
- Transmission costs: related to the tariff for the use of the transmission system (known locally as TUST) charged to transport electricity from generators to consumption centers.
- Sector charges and taxes
- Parcel B represents the O&M expenses related to the electricity distribution, the return on the investments in the concession area, and the depreciation of these assets.
Tariffs are adjusted on an annual basis and reviewed every three to five years, depending on the concession contract. During the tariff reviews, Parcel A is incorporated and the regulator evaluates the incremental asset base since the last review. Then a defined WACC is applied in order to establish the expected rate of return. Currently, the sector is going through its fifth tariff review cycle since the 2004 reorganization, and the regulatory WACC is at 8.09%.
Between each tariff review, the distribution companies receive an annual tariff adjustment, in which non-manageable costs are fully passed through to tariffs and the manageable costs are readjusted to inflation, adjusted by Factor X, which represents the efficiency gain obtained by the distribution company (i.e. due to the growing demand for power). Such efficiency gains are shared with end users.
Although we view the tariff adjustment mechanism as a positive credit factor because it allows the full recovery of Parcel A and adjusts Parcel B costs to inflation, given that it occurs once a year, it could affect the companies' liquidity in case of exceptional spikes in such costs. In response, the regulator established the rate flag mechanism in 2015, which aims to include an additional charge to end users, in order to compensate the distribution companies for higher electricity costs when hydrology conditions worsen and a higher thermal dispatch occurs.
|Category||Additional fee||Unit variable cost (CVU)|
|Green||No charge||Below R$221.28 per MWh|
|Yellow||R$10 per MWh||Between R$221.28 per MWh and R$422.56 per MWh|
|Red – Level 1||R$30 per MWh||Between R$422.56 per MWh and $610 per MWh|
|Red – Level 2||R$50per MWh||Higher than R$610 per MWh|
Finally, regulation allows distribution companies to request extraordinary tariff adjustments in case they believe that their concession contracts are not economically or financially balanced. If ANEEL accepts the request, it grants a tariff adjustment, outside of the regular dates of the tariff readjustment/review.
Transmission revenues are based on their availability, and not on the volume of electricity that passes throughout the lines. The regulator defines a ceiling of annual permitted revenues (Receita Anual Permitida – RAP) for each transmission company, readjusted every July to inflation. The RAP is defined to cover O&M expenses and remunerate investments, and is further discounted to compensate for line availability.
Currently, there are three types of concession contracts in Brazil for the transmission segment, all of which have a 30-year tenor:
- Concessions renewed under the Law 12,783— O&M fees are annually adjusted by inflation, as well as to remunerate new investments in the lines.
- Concessions for those that don't have a periodic rate reset (concessions granted granted between 1999 and November 2006). Their revenues are annually adjusted by inflation, and in the 16th year of the 30-year concession, revenues drop by 50%.
- The newer contracts, in which revenues are annually adjusted by inflation, and every five years the regulator makes a reset in order to remunerate the investments based on the regulatory WACC, which is defined for each reset cycle. In our view, these contracts are most susceptible to regulatory discretion; because the regulator defines the regulatory WACC and reviews the regulatory asset base during the rate reset process.
Annex II: Key Operational Data
|Power Generation Companies (As Of 2018)|
|Company/group||Itaipu Binacional||Eletrobras||Neoenergia S.A.||CPFL Energia||Cemig GT||Rio Paranapanema Energia S.A.||CESP||Santa Vitoria do Palmar||Chapada di Piauí I||Bons Ventos da Serra I||Brazil|
|Installed capacity (MW)||14,000||32,617||4,589||3,272||5,555||2,257||1,655||402||205||23||163,654|
|Assured energy (MW)||7,700||-||2,639||1,532||-||1,063||1,003||169||114||12||-|
|Energy generated (MWh)||98,585,596||135,788,080||-||-||-||12,457,900||9,274,902||1,036,070||-||92,600||546,824,000|
|Sold energy (MWh)||-||145,836,266||-||24,460,000||30,413,938||12,424,313||11,570,306||1,166,242||1,030,128||-||-|
|% of assured energy sold under contracts (ACR and ACL)||-||-||-||78.6||-||79||56.1||-||100||100||-|
|% of assured energy sold under quotas (Law 12,783)||-||-||-||21.4||-||0||0||0||0||0||-|
|Asset mix||100% Hydro plants||85% hydro, 10% thermal, 4% nuclear, and 2% wind||77% hydro, 11.7% thermal, and 11.2% wind||68% hydro, 21% wind, 5% bio, and 5% thermal||94% hydro, 3.6%, renewable, and 2.4% thermal||100% hydro||100% hydro||100% renewable (wind farm)||100% renewable (wind farm)||100% renewable (wind farm)||63.7% hydro, 25.3% thermal, 9.9% renewable, and 1.2% nuclear|
|Distribution Companies (As Of 2018)|
|Group||Energisa S.A.||Equatorial Energia S.A.||CPFL Energia S.A.||Cemig|
|Distribution company||Energisa Paraíba||Energisa Sergipe||CELPA||CPFL Paulista||CPFL Piratininga||RGE||Cemig Distribuição|
|Energy supply revenue (mil. R$)||1,700||1,060||4,188||9,069||3,642||3,010||12,566|
|Consumption of energy (MWh)||3,722,268||2,436,621||7,360,570||20,470,867||7,766,259||6,714,454||25,320,957|
|No. of consumer units||1,424,082||776,347||2,643,582||4,423,385||1,723,075||1,503,413||8,427,063|
|Consumer breakdown (free and captive market)||39.5% residential, 18.4% commercial, 18.5% industrial, and 23.6% others||33.8% residential, 19.1% commercial, 25.1% industrial, and 22% others||42.5% residential, 21.4% commercial, 17.7% industrial, and 18.4% others||30.8% residential, 18.3% commercial, 36.2% industrial, and 14.7% others||27.6% residential, 17.4% commercial, 46.3% industrial, and 8.7% others||36.8% residential, 15.5% commercial, 13.7% industrial, and 33.9% others||23.1% residential, 14.3% commercial, 45.8% industrial, and 16.9% others|
|Energy losses (% of injected energy)||12.64||9.63||28.3||9.09||7.9||8.95||12.48|
|Energy losses regulatory target||12.71||10.12||26.8||8.33||6.92||9.28||11.75|
|DEC regulatory target||17.12||12.39||29.2||7.38||6.74||11.48||10.63|
|FEC regulatory target||10.64||8.88||25.09||6.33||5.82||8.5||7.29|
|Group||Neoenergia||Enel||EDP Energia do Brasil||Light S.A.|
|Distribution company||Elektro||COELBA||CELPE||COSERN||Enel Rio - Ampla||Enel Ceara - Coelce||EDP São Paulo||EDP Espirito Santo||Light|
|Energy supply revenue (mil. R$)||5,385||7,140||4,881||1,855||4,846||4,177||3,867||2,826||10,019|
|Consumption of energy (MWh)||10,806,541||16,515,943||10,904,562||4,629,413||8,569,592||9,810,563||7,940,242||5,842,233||18,517,166|
|No. of consumer units||2,658,301||5,988,190||3,695,868||1,448,708||2,666,088||3,543,253||1,886,173||1,564,005||3,864,698|
|Consumer breakdown (free and captive market)||36.5% free market, 26.9% residential, 13.0% commercial, 9.4% industrial, and 14.2% others||34.9% residential, 17.9% free market, 16.4% commercial, 7.8% industrial, and 22.9% others||36.2% residential, 19.9% free market, 18.1% commercial, 17.7% others, and 7.9% industrial||37.8% residential, 21.0% others, 18.4% free market, 17.2% commercial, and 5.6% industrial||43.3% residential, 21.0% commercial, 20.5% industrial, and 15.3% others||37.1% residential, 23.7% others, 19.8% commercial, and 19.4% industrial||48.3% industrial, 24.7% residential, 16.4% commercial, and 10.6% others||40.8% industrial, 23.4% residential, 18.7% others, and 17.0% commercial||30.7% residential, 27.7% commercial, 23.2% others, and 18.5% industrial|
|Energy losses (% of injected energy)||8.36||14.75||17.33||9.98||21.07||14.25||8.43||11.94||23.95|
|Energy losses regulatory target||6.57||14.32||16.11||10.7||23.54||-||7.75||11.75||20.62|
|DEC regulatory target||8.39||14.5||13.83||12.89||10.46||10.92||7.96||9.78||8.36|
|FEC regulatory target||6.5||8.42||9.27||8.68||7.91||7.82||6.24||7.3||6.05|
|Transmission Lines (As Of 2018)|
|Company/group||Eletrobras -||TAESA||Neoenergia||Cemig GT||Celeo Redes Transmissão de Energia S.A.||Jauru||Norte Brasil Transmissora||Iracema||Cachoeira Paulista|
|Permitted revenue (mil. R$)||10,765||2,663||859||637||192||66||297||22||90|
|Concession maturity||Several maturities||Several maturities||Several maturities||Several maturities||2035-2036||2037||2039||2038||2032|
- Key Credit Factors for the Regulated Utilities Industry, Nov. 19, 2013
- Corporate Methodology, Nov. 19, 2013
- Latin American Utilities: Choppy Trends Amid Stable Performance, July 22, 2019
- Credit Conditions Latin America: Optimism Fades Despite Fed's Pause, June 27, 2019
- Regulatory Support Is Powering Latin America's Utilities, March 8, 2019
This report does not constitute a rating action.
|Primary Credit Analyst:||Vinicius Ferreira, Sao Paulo + 55 11 3039 9763;|
|Secondary Contacts:||Marcelo Schwarz, CFA, Sao Paulo (55) 11-3039-9782;|
|Julyana Yokota, Sao Paulo + 55 11 3039 9731;|
|Research Assistant:||Matheus Ferreira de argollo gusman, Sao Paulo|
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