March 4, 2024

Distribution Tariffs and Risk Management in the Free Energy Market

Helder Sousa*

Summary

Opening the free energy market to all high-voltage consumers marks a significant transformation in the Brazilian power sector. This piece shows how distribution tariffs emerge as key elements in this context, with the financial viability of migration assessed through the breakeven concept. At the same time, analyzing price volatility and managing risks tied to charges such as the system-service charge (ESS) and the reserve-energy charge (EER) are essential to increasing security for both retailers and consumers, especially amid water scarcity and market-price volatility.

Introduction

Liberalizing access to the free energy market for all consumers connected at high voltage, which began in January, is driving significant change in the Brazilian power sector.

In the dynamics of this retail market, electricity tariffs emerge as an even more critical factor than they are in the conventional free market. That's because, for retail traders that commit to contracts offering discounts tied to local distribution companies' rates, each consumer's specific tariff conditions carry important implications both at migration and throughout the life of the contract.

This article outlines the main elements that should be assessed to estimate the breakeven point for analyzing consumer-migration conditions to the free market, including load profile, tariff-flag effects, the distribution company's load density, and the dynamic relationship between the break-even point and market prices, which directly affects the potential for savings.

Additionally, the article shows that the risk inherent to fluctuations in sectoral charges, which are strongly influenced by hydrology and vary monthly in the Electric Energy Trading Chamber's (CCEE) settlement, must be carefully managed by the retailer to ensure the stability and predictability of the service offered.

Finally, the prospect of regulatory changes — through new provisional measures and bills aimed at the power sector — only heightens the need for a deep understanding of tariff conditions and other sector rules.

The fact is that, at this moment of energy-market opening, interest from the client and the trader alone isn't enough for migration: good deals for both parties depend on careful analyses that genuinely lower risk and raise the odds of cutting costs.

Load Profile, a Key Question in the Breakeven

For consumers who choose to contract energy at a fixed price in the free market, migration viability and expected potential savings are often assessed based on the break-even point, or breakeven. This point is the price that makes migrating equivalent to staying in the regulated market (ACR). In other words, for the switch to be financially worthwhile, the free-market energy price must be lower than the breakeven.

The average breakeven for a consumer connected at 13,800 volts (subgroup A4) under the Green tariff modality, with no load-shifting during peak hours, should be BRL 259/MWh for conventional energy after this year's tariff proceedings, according to calculations based on projections from TR Soluções' Energy Tariff Estimation Service (SETE). For incentivized-source energy (i5), the average value rises to BRL 344/MWh. These figures are a market-weighted average across Brazil's 51 concessionaires.

These breakevens are based on a constant energy-consumption profile during peak hours. Consumers with this profile tend to benefit more from migrating, especially if they opt for incentivized energy, which offers discounts on both the demand tariff and the peak-hour energy tariff. This is because transmission (Fio A) and distribution (Fio B) costs are recovered on a binomial basis under the Green modality — part of these costs is billed based on contracted demand, and the other is calculated based on peak-hour consumption.

For a consumer whose load profile shows 100% load-shifting during peak hours — that is, one that disconnects from the grid for three hours on business days — the average breakeven for conventional energy would fall 15%, to BRL 221/MWh. For incentivized-source energy, the reduction would be even more significant, reaching BRL 246/MWh — a decrease of almost 30% compared to the breakeven for a load profile with no peak-hour shifting.

Additionally, these breakeven projections don't factor in any impact from tariff flags. If applied, the break-even value should be adjusted proportionally to the surcharge imposed by the relevant flag.

For context, the chart below shows the trajectory of Brazil's average Electricity Tariff (TE) starting in 2015, along with the TE adjusted to include the additional value from tariff flags, which reflects the average flags applied according to each distribution company's individual contractual calendar. Although the values matched in 2022 and 2023, and are tracking almost the same way this year, the variations were substantial in particular in 2015 and 2021.

Figure 1 -Evolution of the Average TE With and Without Tariff Flags

Load Density's Influence on the Breakeven

At distribution companies with low load density — that is, those with a low number of consumer units per kilometer of grid — the distribution system usage tariff is higher. Consequently, for consumers of these distribution companies, the benefit of migrating to the free energy market becomes more significant, especially when the energy purchased comes from incentivized sources.

To illustrate, while the average breakeven across Brazil's 51 concessionaires for 2024 is projected at BRL 259/MWh for conventional energy sources, Equatorial PA, which holds the highest distribution system usage tariff, ranks 26th in the breakeven ranking. However, when considering incentivized-source energy (i5), the Pará distribution company's breakeven rises to the top of the ranking, exceeding BRL 400/MWh. On the other hand, if the consumer opts to consume incentivized energy and fully shifts their demand away from peak hours, that distribution company's breakeven moves from 1st to 28th place.

Figure 2 - Comparison of the Average Breakeven in Brazil (Projection), Equatorial PA (Current), and Market Prices

So it's essential to assess not just the tariffs charged by the distribution company, but also the client's consumption profile and contracting conditions, for an accurate analysis of migration viability to the free energy market.

So, How Much Will I Actually Save in the Free Market?

Given current market prices, migration proves viable at most distribution companies, even for consumers who fully shift their consumption away from peak hours. Taking into account the average breakeven for conventional-source energy and the Dcide forward-curve indices as of 2/28/2024, prices negotiated for one- to four-year terms are 42% below the break-even point, sitting around BRL 149/MWh. For incentivized-source energy (i5), prices are 47% below the average breakeven, quoted at BRL 183/MWh.

Source: TR Soluções, SETE system, and the Dcide forward-curve index.

But this relationship between breakevens and negotiated free-market prices is dynamic, varying weekly. Given recent hydrological projections, which indicate the possibility of hydroelectric reservoirs reaching 36% of capacity by July, as recently signaled by the National Electric System Operator (ONS), upward pressure on current prices is anticipated, with a trend toward this upward trajectory continuing, although there was a drop in prices this week compared to the previous one.

Sectoral Charge Risk

Captive and free consumers alike pay the System Service Charge (ESS) and the Reserve Energy Charge (EER). The first covers the costs of dispatching thermal plants for various reasons, such as: ensuring demand is met at peak consumption; supplying energy to regions facing supply interruptions due to electrical constraints on the transmission system; maintaining energy security during periods of low water availability; and adding reliability to the power system, among others.

The EER, meanwhile, is meant to cover the costs of contracting reserve energy. The goal is to ensure the system can continuously meet demand, even amid consumption peaks or other contingencies.

These charges are built into tariffs' economic base, with projections prepared by the National Electric Energy Agency (ANEEL) and released every four months. The ESS calculation includes an amount to cover electrical restrictions, given that tariff flags fund dispatches for energy-security reasons when necessary. As for the EER, ANEEL establishes that a fraction of fixed revenue, currently 62%, is recovered via the economic tariff, and not paid directly by captive consumers. All reserve energy is settled at the short-term market price, meaning the charge can be zero if the Settlement Price of Differences (PLD) covers reserve energy's fixed revenue. So, if the PLD rises, the charge's value falls, potentially even resulting in a positive balance. However, if the price hits the minimum, the charge must be billed to honor commitments to reserve-energy generators.

In the future, a third charge, whose regulation is being discussed by ANEEL under Public Consultation No. 061/2021, should join the ESS and EER: the Capacity Reserve Power Charge (ERCAP). The new charge, meant to cover the costs of annually contracting capacity reserve as a power product, should be incorporated into charge risk management starting in the second half of 2026, when supply begins for the first auction of this kind, held in December 2021.

Additionally, the EER could face pressure from changes to the contracting format for the 8 GW of natural-gas thermal plants set out in Law No. 14,182/2021, as anticipated in a version of Bill No. 11,247/2018, the "offshore wind bill," which still has to go through the Senate. For a deeper analysis of contracting these thermal plants, check the article published by TR Soluções last year.

For captive consumers, these charges' costs are reviewed annually, on each distribution company's tariff-event date. For free consumers, however, amounts are settled in CCEE settlement. Retail traders, in turn, need to manage the monthly volatility of these charges, which can exceed BRL 100/MWh during periods of water scarcity, as happened in 2021.

So, understanding the potential volatility of these charges, given the range of hydrological scenarios and energy-contracting conditions, is essential for more efficient risk management, particularly for retail traders.

Final Considerations

The power sector's new dynamic, especially given the context of water scarcity and growing price volatility, expands the risk-management challenges facing traders. The ability to anticipate and respond to tariff fluctuations becomes an essential skill, highlighting the importance of advanced analytical tools to support decision-making. The prospect of regulatory changes through new provisional measures and bills aimed at the power sector only heightens the need for a deep understanding of current tariffs and regulations. After all, these changes have the potential to reshape the power-sector landscape at any moment, and companies must be prepared to quickly adapt their strategies in order to stay competitive and operationally efficient in the new market environment.

* Helder Sousa is Director of Regulation at TR Soluções.