June 16, 2026
Price Signals and Demand Response: the role of batteries in the era of mandatory hourly tariffication
Abstract
This article demonstrates how users of electric vehicles and micro and mini distributed generation (MMDG) combined with energy storage systems (ESS1) can obtain significant economic advantages in a context of mandatory White Tariff application.
Developed as a continuation of the study The end of inertia: how the new White Tariff can reshape the low-voltage market, the work analyzes the potential regulatory and financial impacts of the compulsory transition to this hourly tariff in low-voltage consuming units.
If structured with multiple tariff periods—including a specific overnight period, isolated from the evening peak hour—the hourly tariff transforms into a mutually beneficial tool. On one hand, by fully shifting electric vehicle charging to this off-peak hour, the consumer captures a reduction of up to 90% in transport component costs. On the other hand, the distribution company benefits greatly from the immediate relief of its infrastructure during the critical hour, making the expansion of electromobility not only economically attractive for the owner, but systemically beneficial and sustainable for the electrical grid.
As for the combination of MMDG with ESS, load modulation can zero the grid consumption in the most expensive tariff period and neutralize economic losses imposed by the regulatory discount for consumers with local generation systems. In the case of remote generators, allocating storage directly at the generation site allows retaining daytime production for intentional injection during peak hours. Thus, for White Tariff beneficiaries, each 1.00 kWh injected during peak hour converts into a credit capable of offsetting up to 1.61 kWh of off-peak consumption in the low-voltage period.
Therefore, operational flexibility—whether through intelligent displacement of vehicular loads or strategic use of energy storage systems—goes beyond the emergency supply function in case of grid failures. It not only recovers the economic attractiveness of MMDG in a context of mandatory hourly tariff application but also delivers a relevant service to the Integrated National System (SIN), by reducing pressure on transport infrastructure in critical periods and mitigating the so-called "Duck Curve," smoothing the transition between daytime solar generation surplus and evening peak demand.
1. The regulatory evolution of the White Tariff and the end of tariff inertia
1.1 The history of the voluntary model (opt-in)
The pursuit of efficient economic signalling for consumers connected at low voltage in the Brazilian scenario has deep roots, dating back to the conception of the old Yellow Tariff in 1985. After a long period of maturation in sector discussions, the concept was reformulated and gave rise to the White Tariff through the Normative Resolution No. 733/2016 of the National Electric Energy Agency (Aneel)—subsequently compiled in Normative Resolution No. 1,000/2021.
Conceived under the premise of reflecting hourly costs associated with the provision of transport services on the distribution network (TUSD Transport component), the White Tariff aimed to align billing with the stress that the consumption profile imposes on infrastructure. However, the original voluntary adhesion model proved ineffective. Until 2025, the modality had reached approximately 0.09% of the eligible market in terms of energy consumed.
This scenario is attributed, in large part, to difficulties in communicating with and engaging end consumers, as well as to the regulatory structure defined in Submodule 7.1 of the Tariff Regulation Procedures (Proret) at that time. It is important to note that the model was proposed in a technological context distinct from the current one, when the electrical grid did not yet possess the dynamism and bidirectionality provided today by distributed generation and energy storage systems. In that scenario, simple tariff migration could generate advantages or losses without actually changing consumer behaviour.
To avoid opportunistic movements that could distort the price signal and to preserve the economic-financial balance of concessions—seeking revenue neutrality—the regulator instituted the parameter kz. This lock functioned as a system of checks and balances that, in the context of that era, was seen as necessary due diligence for sector stability. However, in balancing the accounts, this protection mechanism ended up limiting the potential financial gains from the transition. As a consequence, the system froze its own effectiveness of the economic signal it intended to create, draining the primary incentive for users to actively change their consumption habits.
1.2 The "Duck Curve" and the new compulsory approach
The stagnation scenario of the White Tariff collided with the rapid transformation of the generation and load profile of the Brazilian electrical system. The exponential growth of MMDG drove the emergence of the so-called "Duck Curve"—a systemic phenomenon characterized by a severe oversupply of solar energy in mid-day, followed by an abrupt ramp of rising demand and the need to activate thermal generation in the evening.
It is essential to note that tariff modernisation is not a sudden agenda for Aneel. The regulator has been laying this groundwork with structural debates since 2018 (in discussions on binomial tariffs in low voltage), through to the approval of tariff sandboxes in 2022 and, more recently, through Public Inquiry No. 11/2023.
What occurred, in light of the urgency imposed by the "Duck Curve," was a strategic decision to advance the stages of this regulatory roadmap. Aneel shifted its stance towards an assertive induction of efficiency motivated by the confluence of three critical factors: the concrete results obtained in the sandboxes, the maturation of the tariff modernisation agenda, and the urgent need to create real stimuli for load modulation.
Through Joint Technical Note No. 8/2025 and the subsequent issuance of Public Inquiry No. 046/2025, the Agency's technical superintendencies proposed the automatic and compulsory transition to hourly tariffication focused, initially, on large low-voltage consumers. The proposed timeline stipulates that by the end of 2026, all consumers in subgroups B1 (residential), B2 (rural), and B3 (commercial and industrial) with monthly consumption equal to or greater than 1,000 kWh shall be automatically assigned to the new hourly system. Although representing only 2.5% of the total number of consuming units in the segment, this group accounts for significant 25% of its total consumption.
The regulatory planning further proposes an expansion of the consumer base reached from 2027 onwards, reducing the automatic assignment threshold to consumption above 600 kWh/month.
1.3 Marginal costs and the anatomy of usage profiles
To understand how Aneel's methodology transforms users' relationship with the grid, it is imperative to delve into tariff engineering. The tariff calculation model considers dozens of typical usage profiles, known as load curves, segregated by consumption classes, encompassing commercial, industrial, residential, rural, public service, and public lighting sectors. This analytical approach seeks to incorporate into the tariff calculation the sectoral specificities inherent to each segment, such as consumption habits, grid utilization patterns, and equipment ownership.
The true economic thermometer of the system, however, emerges when these behavioural data are overlaid on the physical reality of the electrical infrastructure. The methodology establishes that, by crossing typical usage profiles with the observed loads on distribution networks, the regulator obtains hourly cost curves strictly associated with the provision of transport services.
The result of this crossing reveals the so-called Marginal Costs of Capacity, which estimate the exact economic impact that occurs at the margin of the system: how much it costs to expand or reinforce the distribution network to meet a 1 kW increase in demand.
Within the tariff methodology founded on these parameters, costs are translated into tariff components. These marginal capacity costs underpin and calibrate the value of the TUSD Transport component, acting as a kind of weighting factor among voltage levels that allocate distribution and transmission costs. They seek to ensure that the tariff reflects precisely and technically the real costs of service provision. By revealing the exact cost of each kilowatt required in critical hours, the methodology exposes the weight that the static profile—that is, the inertial and inflexible behaviour of the traditional consumer, who uses energy without responding to price signals—exerts on the distribution network.
Knowing how the distribution company prices the expansion of its network hour by hour, users equipped with automated management systems, analytical capability, and energy storage could actively shape their own load profile. With these technologies, they transition exclusively through the lowest-cost tariff windows, benefiting themselves financially and contributing to optimizing network utilization and mitigating network expansion.
1.4 Simulations of the reformulated tariff under the assumption of behavioural inertia
To understand the real impact of this modernisation, the previous article presented simulations in which the constraints of the parameter kz were removed and a "reformulated" White Tariff was adopted, conceived as a more direct reflection of the marginal capacity costs of networks.
In this approach, the containment mechanism associated with kz was replaced by the traditional method of revenue reconciliation, applied on an aggregate basis by voltage level. With this, the tariff signalling reflects with greater fidelity the hourly costs of electrical infrastructure utilization, exposing and reducing cross-subsidies historically embedded in the conventional tariff, especially those in which commercial and industrial consumers at low voltage end up contributing to finance the network stress caused by evening peak, predominantly residential.
The hypothetical model tested by TR Soluções structured the price signal that would result in a reformulated White Tariff with four well-defined tariff periods:
- Period 1 (Overnight - 23h to 07h59): 90% reduction compared to conventional TUSD Transport;
- Period 2 (Morning - 08h to 13h59): 74% reduction;
- Period 3 (Afternoon - 14h to 17h59): transition zone with subtle 3% reduction;
- Period 4 (Evening - 18h to 22h59): abrupt increase of 240%.
Assuming a premise of absolute behavioural inertia—that is, assuming consumers will strictly maintain their current load curves—simulations based on real concessionaire data reveal a profoundly asymmetric impact among consumption classes. Subgroup B3 (commercial and industrial), whose activity occurs predominantly during daytime, is broadly benefited automatically: 85.1% of its consumers would obtain an average 23.1% reduction in TUSD Transport billing without any change in routine. Likewise, subgroup B2 (rural) presents a highly positive balance, with 73.9% of users capturing an average 22.0% reduction due to already optimised profiles, such as nighttime irrigation.
The major bottleneck lies in subgroup B1 (residential), which accounts for 65.4% of the analysed market. Due to the strong concentration of demand in early evening—driven not only by historical loads but increasingly by new consumption habits generated by economic electrification—behavioural inertia subjected to the reformulated White Tariff would penalise 53.5% of residential consumers. This scenario of passivity would generate an average weighted increase of 22.2% in the transport billing of this contingent, which would push the overall average for subgroup B1 to a 8.0% increase.
1.5 Breaking inertia through technology
The results projected for the residential sector, however, are valid only under the static scenario of consumer passivity. The central thesis brought by the modernisation of the electrical sector is that the imposition of a rigorous, transparent, and technically well-established price signal acts as the primary catalyst for the definitive break of this behavioural inertia. A clear example of this inducing force is the application tariff of BRL 1,622.50/MWh in Period 4 (Evening - 18h to 22h59) described in Table 1—a value that is not an official tariff published by Aneel, but rather the result of the hypothetical White Tariff reformulation model defined by TR Soluções.
Source: ESTRUTURA Platform, TR Soluções.
1.5.1 Viability of electric vehicles
The change in consumption habits, coupled with the viability of new technologies, significantly alters users' relationship with the distribution grid. The accelerated expansion of electromobility is the greatest exponent of this transformation: according to data from the Brazilian Electric Vehicle Association (ABVE), sales of electrified vehicles grew ten times faster than the overall automotive market in 2025, reaching the impressive mark of 224,000 units sold, with an adoption rate even more accelerated recorded in early 2026.
The introduction of battery electric vehicles (BEV) or plug-in hybrids (PHEV), for example, adds a substantial load that can be shifted entirely to overnight (Period 1), allowing a reduction of up to 90% in costs relative to the energy transport component, for the specific case analysed, Cemig.
To ensure a cost comparison adhering to operational reality, the analysis considered the following technical and tax parameters:
- Vehicle efficiency: urban efficiency of 6 km/kWh for the electric vehicle, 12 km/l for gasoline-powered vehicles, and 8.5 km/l for ethanol.
- Fuel cost: market values of BRL 6.29/l for gasoline and BRL 4.21/l for ethanol.
- Effective energy cost: energy tariffs (Cemig) were calculated considering taxes: ICMS (18%), PIS/PASEP (1.25%), and COFINS (5.75%).
- Distance analysed: projection of 1,000 km monthly driving to measure financial impact.
Under this scenario, the difference in operating costs between combustion engines and electric motors is substantial. While monthly fuel spending ranges between BRL 495 (ethanol) and BRL 524 (gasoline), the electric vehicle presents significantly lower costs. However, the effectiveness of this savings depends on consumption habits and the adopted tariff modality:
- Standard cost (Conventional Tariff): under a tariff with fixed energy cost, regardless of hour, monthly cost is BRL 197.
- Maximum optimisation (White Tariff - overnight): vehicle charging restricted to 23h to 8h reduces monthly energy cost to BRL 126, representing approximately 76% savings compared to gasoline use.
- Critical scenario (White Tariff - evening): charging during peak hours (between 18h and 22h59) represents the most expensive tariff condition, raising monthly cost to BRL 355.
It should be noted, however, that the magnitude of this savings has a markedly regional character due to complex Brazilian tax asymmetry. The calculation of effective energy cost, by incorporating 'inclusive' rates, varies strongly depending on billing regulations and ICMS exemption rules in force in each state. Variation in liquid fuel costs also has implications for economic advantages.
The analysis shows that managing electric vehicle costs with the adoption of the White Tariff depends directly on modulating charging habits. Planned overnight charging maximises financial return from the vehicle, while maintaining the Conventional Tariff mitigates exposure to high peak hour costs. In sum, the microeconomic viability of electromobility becomes intrinsically linked to consumer discretion over charging hours.
From the network planner's perspective, the aggregated behaviour of these electric vehicle fleets under different tariff stimuli determines the sustainability of distribution assets. Unordered and concentrated charging in early evening overloads substations and local feeders already operating at capacity due to the traditional residential peak. Therefore, precise calibration of hourly periods in the White Tariff acts as an asset management tool that optimizes infrastructure utilisation factor and postpones the need for investments in transport capacity expansion.
1.5.2 The role of storage in mitigating compulsory tariffication
Figure 1 presents one of the 15 typical residential load profiles used in defining Cemig's tariff structure in the 2023 tariff review. At that time, this profile represented approximately 12% of residential consumption and, in a potential reformulation of the White Tariff along the lines idealised by TR Soluções, this class would be subject to approximately 11% increase in electricity billing.
Source: ESTRUTURA Platform, TR Soluções.
For a 1,000 kWh monthly consumption with the typical profile indicated in Figure 1, without load modulation, the compulsory migration to a reformulated White Tariff, along the lines idealised by TR Soluções, would represent an increase in expenses, raising the monthly bill by BRL 141.24, to BRL 1,374.83. This occurs because the standard behaviour of the residence concentrates much of the use (more than 35%) in the Evening period, and the high cost charged during this peak period completely absorbs any savings generated during cheaper overnight hours.
Therefore, facing the imminent compulsory assignment, consumers maintaining their original habits will face an inevitable increase in operating costs. As changing family's evening consumption routines is, in practice, unfeasible, the definitive technical solution to mitigate this impact would be energy storage and intelligent load modulation.
The installation of a battery bank coupled with large load management enables the displacement of consumption from the critical hour to overnight. To illustrate the financial impact of this strategy, two modulation scenarios were simulated compared to the unmodulated billing of BRL 1,374:
- Partial modulation (peak attenuation): in this scenario, the battery system and automation are configured to supply the house demand only during the initial and most critical hours of the Evening period (from 18h to 20h), transferring system charging to overnight. This manoeuvre generates direct savings of BRL 299 monthly, (approximately BRL 3,600 annually compared to reformulated White Tariff without load management).
Source: ESTRUTURA Platform, TR Soluções.
- Extreme modulation (total evening period displacement): represents the maximum efficiency level. The battery bank and intelligent management would eliminate 100% of the utility grid consumption during the entire Evening period (from 18h to 22h59). Overnight would concentrate nearly 68% of household consumption. The result would be a reduction of the bill to BRL 865. By concentrating energy acquisition during minimum tariff hours and entirely avoiding the peak hour, the system would provide significant savings of BRL 509 monthly (over BRL 6,100 annually) compared to the original reformulated White Tariff bill.
Source: ESTRUTURA Platform, TR Soluções.
1.5.3 Paybacks of energy storage systems
The primary advantage of using energy storage systems for load modulation is the complete preservation of consumer comfort and convenience. Unlike rationing measures, automation with batteries acts imperceptibly, ensuring energy supply while the system manages tariffs autonomously in the background.
From a financial perspective, viability presents itself as highly attractive. To meet the demand of the extreme modulation scenario (which requires storage of approximately 11.8 kWh daily for use during peak hours), a lithium battery bank (LiFePO4) of 15 kWh requires an estimated investment of BRL 20,000—assuming infrastructure already equipped with a hybrid inverter. Given annual savings exceeding BRL 6,100, return on investment (payback) occurs in approximately 3.5 years. As modern lithium modules possess useful life exceeding 10 years (or 6,000 cycles), the equipment ensures over six years of net return after its complete amortisation.
However, despite the high initial financial attractiveness, rigorous viability modelling must necessarily weigh operational stress on system CAPEX and OPEX. The adoption of an extreme modulation scenario, which requires daily deep charge-discharge cycles to completely eliminate consumption during the Evening period, accelerates physical degradation of storage cells. Thus, it is prudent for the prosumer to incorporate into financial planning an annual capacity loss rate ("State of Health – SoH") over the estimated equipment life, in addition to forecasting maintenance costs or eventual hybrid inverter replacement within this long-term horizon, ensuring that projected profitability supports the operational reality of the technology.
It is worth noting that, beyond financial optimisation, adopting this technology elevates the standard of residential electrical installation by providing resilience against supply interruptions. In public grid failure events, the system immediately acts as a high-capacity uninterruptible power supply (UPS), maintaining essential equipment and connectivity in operation. Additionally, hybrid inverters ensure stabilised energy supply, protecting appliances against voltage oscillations and utility grid surges, which prolongs appliance useful life and mitigates losses associated with power quality delivered by the distribution company.
The adoption of the White Tariff finds in energy storage its perfect complement, generating a powerful economic synergy. Far from acting merely as a safeguard against grid failures, the technology establishes itself as an indispensable market tool to mitigate exposure to peak hours, assure financial predictability, and expand residential autonomy.
Thus, the consumer ceases to be a passive element, conditioned to its typical consumption curve, and becomes an active agent in managing its own demand.
2. Batteries and the White Tariff: from perceived risk to regulatory approval
The intersection between the White Tariff and the strategic use of energy storage technology was the epicenter of one of the most intense debates of the 2nd phase of Aneel's Public Inquiry No. 39/2023 (CP 39). At the center of the discussion was the right of access to the hourly modality for low-voltage consuming units (Group B) equipped with colocalised energy storage systems. The trajectory of this debate perfectly illustrates the tension between the regulator's protective conservatism and the inevitability of the energy transition led by the prosumer.
2.1 Agency's concern and access prohibition
In the original draft submitted for public inquiry, Aneel proposed an express prohibition on adhering to the White Tariff for units with colocalised batteries.
The Agency's technical rationale was anchored in system predictability and user protection. This is because the original tariff periods (peak and off-peak) were calibrated based on typical load curves, which do not contemplate the drastic and artificial profile alteration that an energy storage system generates. The Agency's greatest concern was the risk of failure: if the equipment suffered a breakdown or performed below expected precisely during peak hours, when energy is substantially more expensive, the consumer would suffer an increase in billing. Without sufficient time to adequately adjust consumption manually, this abrupt oscillation could, in the Agency's view, trigger a wave of dissatisfaction and complaints.
2.2 Innovation against regression
The proposed restriction was received with strong opposition and unanimously criticised by various entities in the power sector, such as ABEEólica, ABGD, ABSAE, Athon Energia, COGEN, EDP, Bright Strategies, among others. Market agents united to classify the measure as a serious regulatory setback, grounding the defence of liberalisation on the following pillars:
- Maximising systemic benefits: the essence and primary purpose of the White Tariff is to induce consumption displacement to periods of lower demand. The combination with storage potentialises this objective to maximum efficiency, allowing the consumer to purchase energy in the off-peak period (cheap) for consumption or injection during peak hours.
- Immediate grid relief: this operational flexibility drains consumption during the most critical moments of infrastructure stress. This behaviour relieves the SIN and acts directly in postponing investments in network reinforcements and expansion.
- Inconsistency and lack of justification: the entities pointed out that the prohibition was proposed arbitrarily, without having been submitted to a prior Regulatory Impact Analysis (RIA) and without specific technical rationale to justify it.
- Stifling innovation: restricting access to this modality would frontally discourage the deployment of clean and flexible technologies in residential, commercial, and industrial settings. The prohibition would place the Brazilian market at odds with global megatrends of energy transition.
2.3 Technological neutrality and risk assumption
Faced with the robustness of the technical contributions received, Aneel demonstrated institutional maturity by reassessing the issue and retreating from its original position. Its final decision recognised that the systemic benefits provided by active demand management far outweigh the initial concerns. By liberalising access, the regulator embraced the principle of technological neutrality and paved the way for structuring much more sophisticated markets in low voltage, such as demand response programmes, creation of virtual power plants (VPP), and future provision of ancillary services.
However, liberalisation consolidated a new accountability paradigm. Aneel made clear that state stewardship has limits: the consumer who chooses to exploit the White Tariff using batteries assumes full responsibility for risks inherent to equipment operation. If the system fails during peak hours, the consumer will bear the financial exposure to the increased tariff. It is a fair counterpart of modernisation: the freedom to manage one's own demand and mitigate system costs requires planning, adequate maintenance, and risk management by the new consumer.
3. Tariff asymmetry and ESS as the great equaliser
The transition to the White Tariff exposes an inherent vulnerability to consumers benefiting from MMDG. While on one hand distributed generation democratised access to clean energy, on the other, hourly tariffication introduces a severe financial obstacle for these systems. In this scenario, ESS can consolidate as a market viability solution, as well as a vector for maturing more sophisticated business models that aggregate benefits for both prosumers and the system.
3.1 Temporal mismatch and the adjustment factor (energy value loss)
The traditional model of MMDG solar, whether local or remote, suffers from a temporal mismatch relative to moments of greatest system stress. The plant injects its maximum energy volume to the grid during the day, a period that coincides with the Off-Peak period of the White Tariff. The problem arises when the consuming unit linked to MMDG uses this energy at night, usually during Peak hours, characterised by substantially higher costs.
Under the current compensation rules, energy is not exchanged simply in the proportion of "one-to-one" when energy is compensated at a different hour than when it was injected. Regulations require that the offset adhere to the economic relationship between Energy Tariffs of the tariff periods (Peak TE / Off-Peak TE).
Technical discussions raised during CP 39 pointed out that, historically, this adjustment factor has varied on average between 1.6 and 2.1 in Brazil. In practice, this creates significant financial asymmetry: the consumer must generate and inject approximately 2 kWh of solar energy to the grid during the day to be able to offset only 1 kWh of consumption during evening peak hours. The result is massive loss of efficiency in compensation, drastically reducing the attractiveness and financial return of investment in local and remote plants for customers subject to hourly tariffs.
3.2. ESS colocalised at load: arbitrage and tariff protection
To circumvent this penalty imposed by the adjustment factor, introducing an ESS colocalised at the consuming unit acts as the perfect shield. Storage resolves the inefficiency of temporal mismatch by allowing the consumer to arbitrage energy use.
The operational strategy becomes simple and highly profitable:
- Charging (Off-Peak): the consumer programmes its battery to charge during the day, absorbing grid energy. As this consumption occurs during Off-Peak hours, it is offset in the ideal 1-to-1 proportion by credits generated simultaneously by its solar plant.
- Discharging (Peak): when the system enters Peak hours and the tariff reaches its price peak, the consumer supplies its internal load from the battery.
With this manoeuvre and depending on system sizing, the consumer can zero their grid consumption during the most expensive hour, shielding themselves against the "discount" on energy. ESS maximises the value of solar credits, ensuring that all generated energy is leveraged at maximum economic efficiency, without the losses imposed by conversion between tariff periods.
3.3. ESS at generation: reversing market logic
The potential of storage expands even further when analysing its installation directly at the remote MMDG plant. This alternative, widely advocated by market agents, allows avoiding losses and reverses the adjustment factor rule in the consumer's favour.
By associating batteries to the generation location, the developer can store solar energy production throughout the day, intentionally injecting it into the grid during Peak hours. Under this configuration, the regulatory asymmetry acts as a leverage for benefits:
- Credit multiplication: as injection occurs during the period when Energy Tariff (TE) is most expensive, each 1 kWh injected during peak hours becomes worth much more, generating multiplied credits to be used during other hours.
- Exponential offset: these "valued" credits can offset a significantly larger volume of consumption during the Off-Peak periods of the various beneficiary units of the consortium or cooperative.
To illustrate this mechanism, imagine a scenario where the TE in A4 and in BT are those highlighted in the following tables:
Source: Aneel Homology Resolution No. 3,589/2026.
Source: Aneel Homology Resolution No. 3,589/2026.
When installing ESS colocalised with the plant in A4, the battery stores solar energy generated during the day and intentionally injects it to the grid during Peak hours. At that moment, injection becomes valued by the adjustment factor rules, which are based on the Energy Tariffs (TE) of the beneficiary unit itself. Thus, market logic reverses in favour of the consumer subject to hourly modality (White Tariff):
- The adjustment factor becomes a relevant "premium." The relationship (Peak TE White / Off-Peak TE White) is 474.50 / 295.27, resulting in an adjustment factor of 1.61.
- Each 1 kWh of energy stored and injected by the A4 plant during peak hours transforms into credit sufficient to offset 1.61 kWh of daytime consumption (Off-Peak) in Low-Voltage units.
In the case where the BT consumer is subject to the Conventional Tariff, regulations establish that energy injected during peak hours will be treated with a 1-to-1 relationship, without the incidence of the hourly adjustment factor.
Beyond the clear economic advantage, this strategy provides an important service to the SIN. The concentrated injection of energy during peak hours relieves the distribution and transmission network infrastructure precisely when it is most demanded, mitigating the harmful effects of the "Duck Curve" and reducing the risk of evening overloads. Furthermore, it is precisely this type of demand response that makes it possible to mitigate the need for capacity reserve contracting to meet SIN power requirements.
In summary, whether protecting the end consumer at the consumption peak or multiplying credits at the generation peak, energy storage systems establish the physical infrastructure necessary to enable demand response mechanisms. As already discussed in a previous article published by TR Soluções on the escalation of Power Charge costs for Capacity Reserve (ERCAP), whose projections for 2032 point to a peak in sector collection of BRL 53 billion resulting from power auctions, equipping consumers with predictive capability and active load modulation transforms the passive user into a strategic agent for SIN stabilisation. Energy storage, coupled with efficient tariff signals, proves to be the missing piece in the White Tariff puzzle, converting a rate adjustment risk into a tool for tariff affordability and systemic efficiency.
Despite its undeniable benefits, it is imperative that market agents recognise that tariff arbitrage at remote generation (A4) carries latent regulatory risk. Historically, Aneel has acted to curb mechanisms it interprets as purely financial arbitrage, especially if the scale gain provided by storage begins to translate into an unforeseen drain on distribution company compensation accounts. As the use of batteries for intentional credit multiplication during peak hours gains massive commercial traction, it is highly likely that this 'logic reversal' will face severe scrutiny in future tariff review cycles or in subsequent updates to Normative Resolution No. 1,000/2021. Therefore, remote plant investors must structure their business models anticipating not only legal safeguards but also regulatory stress scenarios that contemplate potential changes in adjustment factors and hourly injection rules.
4. Conclusion
The imminent compulsory transition to the White Tariff represents a watershed moment in the Brazilian power sector, definitively ending the era of tariff inertia for large low-voltage consumers. While, on one hand, this regulatory shift imposes a financial burden on traditional consumption profiles and exposes MMDG's temporal mismatch, on the other, it opens a window of opportunities for active demand management.
As demonstrated, the adoption of load flexibility technologies acts as the primary catalyst for this new reality. The strategic modulation of large loads—such as electric vehicle charging shifted to overnight—illustrates the ability to drastically reduce charging expenses by directly benefiting from the transport component's price signalling. However, it is the integration of Energy Storage Systems (ESS)—represented in the market primarily by battery systems (BESS)—that promotes the true disruption in the sector's business models.
From a systemic perspective, the benefits of this break in behavioural inertia overflow beyond the boundaries of individual cost reduction for large low-voltage consumers. By attenuating load ramps and flattening system demand peaks, the aggregated use of distributed batteries acts as a decentralised flexibility resource and operational security tool. This advance directly reduces the need for the power concedent to activate more expensive resources in critical moments or conduct capacity reserve auctions for power purposes, whose billion-dollar costs are rationed across all users. Rather than relying on complex regulation on equipment installed behind the meter, the consolidation of price signals that encourage tariff arbitrage and intelligent demand management—made viable by a compulsory White Tariff adherent to real costs—emerges as the most feasible and immediate alternative to relieve the sector charges that today weigh on the national electrical matrix.
Batteries consolidate as the great regulatory equaliser. Whether located at the load to shield the consumer against high peak-hour costs, or installed at remote generating plants to promote adjustment factor arbitrage—converting energy discount into economic gain in compensation—storage reverses market logic in the investor's favour.
Ultimately, ESS ceases to be a niche technology or mere contingency mechanism to establish itself as the cornerstone of the modern prosumer's economic viability. Beyond assuring profitability, predictability, and financial independence, strategic insertion of batteries and load modulation deliver an essential service to the Integrated National System's stability, relieving infrastructure stress during critical hours and enabling a more efficient, intelligent, and resilient energy transition.