SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of the

Securities Exchange Act of 1934

For the month of November, 2025

Commission File Number 1-34129

CENTRAIS ELÉTRICAS BRASILEIRAS S.A. - ELETROBRÁS

(Exact name of registrant as specified in its charter)

BRAZILIAN ELECTRIC POWER COMPANY

(Translation of Registrant's name into English)

Rua da Quitanda, 196 – 24th floor,
Centro, CEP 20091-005,
Rio de Janeiro, RJ, Brazil

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F. 

Form 20-F ___X___ Form 40-F _______

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes _______ No___X____

AXIA ENERGIA RELEASES 3rd QUARTER 2025 RESULTS

Highlights:

Shareholder remuneration: R$ 4.3 billion in dividends, totaling R$ 8.3 billion distributed in fiscal year 2025, reaching approximately R$ 4.01 per Class A and Class B preferred share, and R$ 3.65 per common share and golden share.

In September and October, Management delivered significant and consistent results, notably with the signing of the sale of Eletronuclear, the divestment of the stake in EMAE, and the acquisition of Tijoá Energia, accelerating the Company’s streamlining process and reducing its risk profile. These developments, together with the strong results achieved in 3Q25, resilient 2026 prices, advances in energy trading, and improvements to our long-term energy model, generated allocable capital under our capital allocation methodology. This, in turn, enabled both the dividend proposal and participation in the transmission auction No. 4/2025. The capital allocation methodology underscores our commitment to financial discipline, shareholder value creation, and sustained investment capacity.

Transmission auction No. 4/2025: winning bid of lots 6A, 6B, 7A and 7B, with RAP of R$ 138.74 million and CAPEX projected by ANEEL of R$ 1.63 billion, attesting to AXIA Energia's competitiveness and efficiency.

Adjusted Regulatory Net Revenue: R$ 9,969 million in 3Q25, down 4.6% YoY, with higher transmission revenues partially offsetting the lower generation revenue related to the sale of the Amazonas thermal power plants and the additional sale of energy from the Tucuruí HPP, which occurred only in 3Q24.

Contribution margin from generation, ACL + MCP: The contribution margin from energy traded in the Free Contracting Environment (ACL) and settled in the Short Term Market (MCP) increased to R$ 86/MWh in 3Q25 from R$ 48/MWh in 3Q24, considering the resources available for allocation in both segments.

Energy trading: 813 clients served in 3Q25, up 16% YoY, with 723 in the ACL compared to 614 in 3Q24.

Adjusted Regulatory EBITDA excluding the variation in results from the Amazonas thermal plants sold in 2025: EBITDA reached R$ 6,419 million in 3Q25, up 3.4% YoY, driven by the 9.8% increase in transmission revenues along with the 10.1% drop in PMSO expenses, reflecting the Company's focus on continuously enhancing operational efficiency. These advances more than offset the 2.1% decrease in generation revenue and the 21.9% reduction in equity income, ensuring resilient EBITDA growth.

Adjusted IFRS Net Income: Totaled R$ 2,176 million, down 68.0% YoY, due to the recognition of a R$ 303 million regulatory remeasurement in 3Q25, compared to R$ 6,130 million in 3Q24, when the impact of the 2023 Periodic Tariff Review was recognized, with no equivalent effect in 2025.

Investments: R$ 2,701 million in 3Q25, up by 32% and 57% compared to 2Q25 and 3Q24, respectively. It is worth noting the 28% YoY increase in investments in reinforcements and improvements in the transmission segment, which reached R$ 1,061 million in 3Q25.

Still within the transmission segment, 230 large-scale projects are under implementation, representing an additional RAP of R$ 1.7 billion between 2025 and 2030 and a total estimated CAPEX of R$ 12.5 billion.

100% Renewable Portfolio: In October, we completed the sale of our last thermal power asset, the Santa Cruz TPP. With this transaction, AXIA Energia now holds a 100% renewable portfolio, in line with its Net Zero 2030 commitment.

Portfolio Management Oct/25: Agreement for the sale of stake in Eletronuclear to J&F for R$ 535 million, providing for the release of guarantees granted by AXIA Energia and the transfer of the “ADI debentures.” The buyer will assume full responsibility for the payment of these debentures, totaling R$ 2.4 billion, as established in the Settlement Agreement with the Federal Government.

Execution of the contract for the sale of AXIA Energia’s stake in Empresa Metropolitana de Águas e Energia S.A. (EMAE) to Companhia de Saneamento Básico do Estado de São Paulo (SABESP) for R$ 476.5 million, including the possibility of future earn-out payments.

Acquisition of the remaining 50.1% stake in Tijoá Energia, in October 2025, for R$ 247 million. The plant has an installed capacity of 808 MW and, in 2024, achieved annual revenue of R$ 320 million and EBITDA of R$ 136 million.

Financial management: net debt totaled R$ 42,577 million in 3Q25, up by R$ 2,451 million and R$ 3,680 million compared to 2Q25 and 3Q24, respectively. This increase was due to the higher gross debt and lower available cash, resulting from the R$ 4 billion dividend payment in August 2025, which consumed a portion of the R$ 5 billion in free cash generated during the period. The average debt maturity decreased by 3.9 months while the average cost rose to CDI + 0.64% p.a. from CDI + 0.59% p.a. in 3Q24.

Notably, Eletronorte raised R$ 2 billion through a debenture issuance in July 2025, with a final cost equivalent to CDI -0.56% p.a. after a swap transaction.

Compulsory Loan: the provision inventory was reduced by R$ 2.7 billion YoY and R$ 362 million sequentially, totaling R$ 11.7 billion in 3Q25. Agreements reached and favorable decisions led to a net reversal of R$ 300 million in the quarter.

MAIN OPERATIONAL AND FINANCIAL INDICATORS

Table 1 - Operating highlights

(1) Assured Capacity (AC) reflects: (a) Ordinance GM/MME 544/21, which established the revision of AC values for plants that had their concessions renewed due to the capitalization (Quota regime plants: Tucuruí, Itumbiara, Sobradinho, Mascarenhas de Moraes, and Curuá-Una), leading to a significant AC reduction, effective from 2023; (b) Ordinance GM/MME 709/22, which introduced an Ordinary Review of the AC for hydroelectric power plants effective from 2023, impacting several AXIA Energia plants; (c) exit of TPP Candiota III as of Jan/24 and of TPPs Mauá III, Aparecida, Anamã, Anori, Codajás, and Caapiranga as of May/25; (d) inclusion of Colíder HPP and exclusion of Mauá HPP as of June/25, following the uncrossing of asset holdings with Copel; (e) inclusion of newly consolidated SPEs: Teles Pires HPP (Oct/23), Baguari HPP (Oct/23), Retiro Baixo HPP (Nov/23), and Santo Antônio HPP (Nov/23); (f) inclusion of the expanding wind farms Casa Nova B and Coxilha Negra, with full AC in 2024; (g) figures do not yet reflect the completion of the sale of the Santa Cruz TPP, concluded in Oct/25, nor the consolidation of the Três Irmãos HPP, whose signing occurred in Oct/25 and is still pending completion.

(2) Does not include quotas.

(3) Includes contracts under Law 13.182/2015.

(4) The figures presented refer to the Assured Capacity of quotas in GWh.

(5) Excludes thermoelectric power plants.

(6) Approved RAP for the current regulatory cycle, considering the modules in operation at the end of each period—including those in operation at the start of the cycle, as well as new modules that entered commercial operation. Includes transmission contracts from AXIA Energia Holding, Chesf, CGT Eletrosul, Eletronorte, TMT, and VSB.

Table 2 - Financial highlights

HIGHLIGHTS OF CONSOLIDATED RESULTS

1.              CONSOLIDATED RESULT | IFRS AND REGULATORY

Table 3 - Income statement IFRS (R$ mm)

(1) The adjusted value originally disclosed for the Income Tax and Social Contribution line in 3Q24, published on November 6, 2024, was -R$ 1,186 million. Subsequently, part of the deferred tax recognized in 4Q24, amounting to R$ 758 million, was identified as having its triggering event in 3Q24. Accordingly, a non-recurring adjustment was made between the two quarters, reallocating this amount from 4Q24 to 3Q24, with no impact on full-year 2024 results. As a result, in the 4Q24 disclosure, the adjusted value for 3Q24 was revised from -R$ 1,186 million to -R$ 1,944 million. The value presented for 3Q24 in this earnings release reflects the revised amount, as disclosed in the 4Q24 results on March 13, 2025.

Table 4 - Regulatory IS (R$ mm)

(1) The figures for 3Q24 presented in this disclosure differ in two lines from those originally published on November 6, 2024. Gross transmission revenue decreased by R$ 147 million, from R$ 4,467 to R$ 4,320 million, while the cost of network usage charges—recorded under “Energy resale, grid, fuel and construction”—also decreased by R$ 147 million, from R$ 3,135 million to R$ 2,988 million. As a result, the net effect on EBITDA and net income is nil. The change in both lines results from the review of accounting practices in 2025 related to the elimination of intercompany transactions between the Company’s generation and transmission segments, This adjustment reflects that network usage charges paid by certain generation plants are offset by revenues received by the transmission companies within the group. To ensure comparability between 2024 and 2025, the corresponding elimination values for 2024 were also revised.

(2) The adjusted value originally disclosed for the Income Tax and Social Contribution line in 3Q24, published on November 6, 2024, was -R$ 410 million. Subsequently, part of the deferred tax recognized in 4Q24, amounting to R$ 758 million, was identified as having its triggering event in 3Q24. Accordingly, a non-recurring adjustment was made between the two quarters, reallocating this amount from 4Q24 to 3Q24, with no impact on full-year 2024 results. As a result, in the 4Q24 disclosure, the adjusted value for 3Q24 was revised from -R$ 410 million to -R$ 1,168 million. The value presented for 3Q24 in this earnings release reflects the revised amount, as disclosed in the 4Q24 results on March 13, 2025.

2.              ADJUSTED CONSOLIDATED RESULT | IFRS AND REGULATORY

Adjusted Regulatory Income Statement

This section presents the reconciliation between Regulatory and IFRS Income Statements, along with the adjustments related to non-recurring events in the Regulatory Income Statement.

A detailed reconciliation is also available in the “Regulatory and IFRS Income Statement Reconciliation” spreadsheet, accessible on the Company’s Investor Relations website, under Market Information > Historical Financial Information.

Table 5 - Regulatory IS x IFRS IS (R$ mm) 

Non-recurring Adjustments

The following adjustments refer to events considered non-recurring:

(a) R$ 266 million in provisions for litigation;

(b) -R$ 176 million in reversals of provisions for estimated losses on loans and financing;

(c) -R$ 29 million in appropriation of onerous contracts;

(d) R$ 15 million in adjustments related to the compulsory loan share conversion process;

(e) -R$ 12 million in estimated losses on investments and non-recoverable assets (impairment)

Regulatory Result: Adjusted EBITDA

In 3Q25, adjusted regulatory EBITDA totaled R$ 6,382 million, down R$ 393 million YoY, reflecting:

(a) the drop in generation revenue due to the sale of the Amazonas thermal power plants and the additional energy sale from Tucuruí HPP which occurred only in 3Q24;

(b) lower reversals of provisions; and

(c) a reduced contribution from equity holdings.

These effects were partially offset by:

(a) higher transmission revenue;

(b) lower PMSO costs and expenses; and

(c) reduced fuel costs for electricity generation following the sale of the Amazonas thermal power plants.

Equity income was R$ 476 million in 3Q25, and does not include the net income from the stake in Eletronuclear, which was classified as asset held for sale following the signing of the divestment agreement with J&F.

It is worth noting that, excluding the results from the Amazonas thermal power plants, sold in May 2025, EBITDA went up R$ 214 million to R$ 6,419 million in 3Q25 from R$ 6,205 million in 3Q24.

Table 6 - Adjusted regulatory EBITDA, without thermal power plants (R$ mm)

Generation revenue was R$ 6,775 million in 3Q25, down R$ 1,225 million YoY. Recurring revenue fell 15.3% reflecting decreases of 12.3% in volume and 3.4% in average price. The reduction in both volume and price can be explained by:

(a) the sale of Amazonas thermal power plants, and

(b) the additional sale of energy from Tucuruí HPP in 3Q24, due to the renegotiation of hydrological risk, an event without a counterpart in 3Q25.

Excluding the revenue billed from energy sold by the thermal power plants, generation revenue was down by R$ 144 million, reaching R$ 6,575 million in 3Q25, reflecting an 8.5% drop in volume, partially offset by a 6.9% increase in average price. In 3Q25, revenue was positively impacted by higher energy settlements in the Short Term Market (MCP) amounting to R$ 1,755 million, compared to R$ 695 million in 3Q24. This increase reflected the combined increases of 38% in average price and 83% in volume.

Costs associated with generation reached R$ 2,555 million in 3Q25, up by R$ 400 million YoY, of which R$ 380 million relate to higher expenses with energy purchased for resale.

Transmission revenue increased by R$ 425 million YoY, reaching R$ 4,745 million in 3Q25, mainly reflecting a reduction in the negative component of the Adjustment Portion (PA).

Personnel, Materials, Services and Other (PMSO) expenses fell by R$ 168 million, totaling R$ 1,499 million in 3Q25. The decrease resulted from measures implemented by the Company to enhance operational efficiency.

Provisions under the regulatory view showed a reversal of R$ 207 million in 3Q25, compared to R$ 29 million in 3Q24. This variation reflects the R$ 170 million reversal in 3Q25 related to Amazonas Energia debts with AXIA Energia, following the release of judicial deposits made by the counterparty.

3Q25’s performance reflected positive effects from higher transmission revenue and lower PMSO and provision expenses, reflecting the Company’s continuous pursuit of operational efficiency and mitigation of contingencies. These improvements more than offset the lower contribution from the generation segment and from equity income, ensuring resilient EBITDA growth.

IFRS Result: Adjusted EBITDA and Net Income

Adjusted IFRS PMSO was R$ 1,509 million, down 10.8% YoY, reflecting savings related to efficiency gains. In 3Q25, the adjusted PMSO was impacted by the following effects:

(a) R$ 82 million related to Voluntary Dismissal Programs (VDPs) and severance costs;

(b) R$ 18 million related to commitments under the self-managed health plan, which was replaced by a plan managed by a specialized market operator;

(c) R$ 15 million in legal consulting costs related to the contingency reduction strategy.

Adjusted IFRS EBITDA reached R$ 5,890 million in 3Q25, down 50.8% YoY. This variation was mainly explained by the recognition of a R$ 303 million regulatory remeasurement in 3Q25, compared to R$ 6,130 million in 3Q24, when the impact of the 2023 Periodic Tariff Review was recognized, with no equivalent effect in 2025.

Adjusted IFRS Financial Result reached -R$ 2,385 million in 3Q25, compared to -R$ 2,225 million in 3Q24.

Adjusted Income Tax and Social Contribution tax expenses under IFRS reached R$ 173 million in 3Q25 compared to R$ 1,944 million in 3Q24, due to lower recognition of deferred tax expenses.

Thus, Adjusted IFRS Net income reached R$ 2,176 million, down 68.0% YoY.

3.              ENERGY TRADING

AXIA Energia companies sold 94.7 TWh of energy in 3Q25, down 7.8% compared to the 102.6 TWh traded in 3Q24.

The volumes sold include energy from plants under the quota regime, renewed under Law 12,783/2013, as well as from plants operating under the ACL and ACR exploration regimes and consolidated Special Purpose Entities - SPEs: HPPs Teles Pires and Baguari (as of Oct/23), and Retiro Baixo and Santo Antônio (as of Nov/23).

Table 7 - Energy balance 3Q25 (aMW)

Contracts signed until 9/30/2025.

The energy balance reflects the SPEs consolidated into AXIA Energia: Santo Antônio HPP (as of 3Q22) and Baguari and Retiro Baixo HPPs (as of 4Q23) in terms of resources, sales, and average prices. Similarly, Teles Pires HPP, an SPE consolidated into Eletronorte (as of 4Q23), is also included.

Table 8 - Assured capacity quotas of hydroelectric power plants (aMW)

4.              INVESTMENTS AND EXPANSION PROJECTS

Investments totaled R$ 2,701 million in 3Q25, with allocation as follows:

(a) R$ 1,203 million to transmission;

(b) R$ 677 million to Itaipu's HVDC project;

(c) R$ 289 million to generation;

(d) R$ 282 million to equity holdings;

(e) R$ 181 million to infrastructure; and

(f) R$ 69 million to the environmental area.

It is worth highlighting the higher investments related to the revitalization of the Itaipu High Voltage Direct Current (HVDC) system, which transmits energy generated by the power plant to consumer centers in Brazil. The project results from a technical and financial cooperation agreement between AXIA Energia, which is responsible for execution, and Itaipu, which fully reimburses the investments, with funds released in advance of disbursements.

The amount invested in infrastructure was allocated as follows:

(a) 36% for IT;

(b) 28% for socio-environmental initiatives;

(c) 19% for real estate; and

(d) 17% for equipment and vehicles.

In the socio-environmental area, key highlights included investments related to the maintenance of operating licenses for power plants and substations, as well as land compensation.

The breakdown of investments by the holding company and its main subsidiaries is available in the operational spreadsheet in the Results Center section of the Company’s Investor Relations website.

Table 9 - Investments (R$ mm)

Expansion Projects - Transmission

Large Scale Projects

Small Scale Projects

Table 10 - Portfolio of ongoing transmission projects

[1] Referring to reinforcements, improvements and auction-related projects. Considers projects registered in ANEEL's Transmission Management System (SIGET). Projects are included when added to the system and excluded when they are either canceled or enter commercial operation. The 230 projects will add 2,306 km of transmission lines and 12,926 MVA in substations.

[2] Each of the 5 SPEs created holds the contracts signed in last years' transmission auctions. SPE Nova Era Janapu holds contract no. 09/2023-ANEEL for the 4th lot of Auction 01-2023; SPE Nova Era Teresina holds contract no. 04/2024-ANEEL for the 1st lot of Auction 01-2024; SPE Nova Era Ceará holds contract no. 06/2024-ANEEL for the 3rd lot of Auction 01-2024; SPE Nova Era Integração holds contract no. 08/2024-ANEEL for the 5th lot of Auction 01-2024; and SPE Nova Era Catarina holds contract no. 12/2024-ANEEL for the 9th lot of Auction 01-2024.

5.              INDEBTEDNESS

Net debt totaled R$ 42,577 million in 3Q25, up R$ 2,451 million sequentially and R$ 3,680 million YoY. As a result of liability management and a 425 bps increase in the Brazilian basic interest rate (Selic), the Company's average debt maturity was reduced by 3.9 months in 3Q25 when compared to 3Q24, while the total average cost increased to CDI + 0.64% p.a. in 3Q25 from CDI + 0.59% p.a. in 3Q24.

Table 11 - Net debt (R$ mm)

Below are the gross debt maturity schedule and its breakdown by index, according to the index profile, as well as the respective spreads over each index, considering gross debt including derivatives. A more detailed breakdown is available in the operational spreadsheet in the Results Center on the Company’s Investor Relations website.

Chart 1 - Debt maturity schedule after hedge (R$ billion)

Table 12 - Debt breakdown, including hedge

6.              COMPULSORY LOAN

AXIA Energia has implemented measures to mitigate risks associated with legal proceedings related to compulsory loans on electricity[1]. To address this, the Company has strengthened its legal defense strategy and pursued settlements with discounts and full resolution of lawsuits. As a result of the negotiations:

Since 3Q22, when negotiations began, the provision inventory related to compulsory loan fell by R$ 14.2 billion, reaching R$ 11.7 billion in 3Q25, even considering the accumulated R$ 2.9 billion monetary restatement in the period. The agreements also enabled the elimination of R$ 10.1 billion in legal risks considered "off balance", of which R$ 930 million was classified as possible and R$ 9.2 billion as remote.

Chart 2 - Total inventory of compulsory loan provisions 3Q25 x 3Q24 (R$ bn)

Chart 3 - Total inventory of compulsory loan provisions 3Q25 x 2Q25 (R$ bn)

[1] Starting in 3Q25, the figures presented in this section fully encompass all procedural matters related to the topic, rather than only the book-entry credits, which represented approximately 99% of the total balance and had been the focus of this section in previous quarters. As a result, the figures disclosed herein may show slight variations compared to those reported in prior periods.

7.              CASH FLOW

It is worth highlighting for 3Q25 the R$ 4 billion dividend payment in August 2025.

Table 13 - Cash flow (R$ mm)

*Does not take into account the adjustment related to asset disposal in the net profit line.

**Excludes generation contributions.

***Net funding: debt raised, net of issuance costs.

FINANCIAL AND OPERATIONAL RESULTS ANALYSIS

8.              FINANCIAL PERFORMANCE

8.1.      Operational and Financial Results

The table below presents the results by segment for the AXIA Energia Group’s two main businesses—generation and transmission—considering revenue and direct costs. Other costs and expenses, results from equity holdings, financial results, and taxes are analyzed on a consolidated basis.

Table 14 - Income statement 3Q25 (R$ mm)

(1) Eliminations: These refer to the portion of transmission system usage charges paid by AXIA Energia's generators to the Company's own transmission companies, which receive them in the form of RAP. For accounting consolidation purposes (Tables 4 and 5), these amounts are eliminated from both transmission revenue and generation usage charges. For management purposes, gross transmission revenue in 3Q25 is R$ 5,020 million, and including the accounting elimination of -R$ 276 million, this translates into accounting revenue of R$ 4,745 million. In the case of generation connection charges costs, for management purposes, the value in 3Q25 is -R$ 1,132 million, and including the accounting elimination of R$ 276 million, this translates into an accounting cost of -R$ 857 million.

(2) The "RHR Hedge Cost" and "Other Operating Costs" lines, related to the generation segment costs, make up the "Other PMSO Costs" line under the accounting view. For a better understanding of the contribution margin by segment, from a management perspective, both lines are allocated in the composition of the contribution margin from generation. In 3Q25, the adjusted regulatory PMSO under the accounting view totaled R$ 1,505 million, composed of R$ 19 million in RHR hedge costs and R$ 13 million in other generation operating costs, both allocated in the margin from generation, and R$ 1,474 million in other cost and expense components for personnel, materials, services and others. At the same time, in 3Q25, the adjusted IFRS PMSO from an accounting perspective totaled R$ 1,509 million, comprised of R$ 19 million in RRH hedging costs and R$ 13 million in other generation operating costs, both allocated to the margin from generation, and R$ 1,478 million in other cost and expense components related to personnel, materials, services, and others.

Table 15 - Income statement 3Q24 (R$ mm)

(1) Eliminations: These refer to the portion of transmission system usage charges paid by AXIA Energia's generators to the Company's own transmission companies, which receive them in the form of RAP. For accounting consolidation purposes (Tables 4 and 5), these amounts are eliminated from both transmission revenue and generation usage charges. For management purposes, gross transmission revenue in 3Q24 is R$ 4,575 million, and including the accounting elimination of -R$ 255 million, this translates into accounting revenue of R$ 4,320 million. In the case of generation connection charges costs, for management purposes, the value in 3Q24 is -R$ 1,123 million, and including the accounting elimination of R$ 255 million, this translates into an accounting cost of -R$ 869 million.

(2) The "RHR Hedge Cost" and "Other Operating Costs" lines, related to generation segment costs, make up the "Other PMSO Costs" line under the accounting view. For a better understanding of the contribution margin by segment, from a management perspective, both lines are allocated in the composition of the contribution margin from generation. In 3Q24, the adjusted regulatory PMSO under the accounting view totaled R$ 1,702 million, composed of R$ 91 million in RHR hedge costs and R$ 9 million in other generation operating costs, both allocated in the margin from generation, and R$ 1,602 million in other cost and expense components for personnel, materials, services and others. At the same time, in 3Q24, the adjusted IFRS PMSO from an accounting perspective totaled R$ 1,692 million, comprised of R$ 91 million in RRH hedging costs and R$ 9 million in other generation operating costs, both allocated to the margin from generation, and R$ 1,592 million in other cost and expense components related to personnel, materials, services, and others.

8.2.      Generation Segment

Revenue by Contracting Environment

Recurring regulatory revenue was R$ 6,775 million in 3Q25, R$ 159 million lower than adjusted IFRS generation revenue. This difference reflected the accounting treatment of the portion of revenue from Amazonas Energia related to previously unpaid amounts, following a change in the assessment of receivables. Under IFRS, these amounts were recognized as revenue, while under regulatory accounting—where such recognition had already occurred—there was also a reversal of the provision recorded at that time. The difference, which had been recognized in previous comparison periods, had the same nature at that time.

Two effects on energy sales in the regulated market deserve highlight:

(a) the contractual extension and sale of additional energy in 3Q24, without a counterpart in 3Q25, related to the renegotiation of the hydrological risk of Tucuruí HPP, and

(b) the 84% reduction in revenue from the sale of thermal energy, which in 3Q25 included only the Santa Cruz TPP, whose sale was completed on October 9, 2025.

Regarding non-recurring effects in the quarter, a negative impact of R$ 26 million was recorded, stemming from adjustments to the value of thermal power plant sale transactions. The adjustment relates to obligations and rights with maturities extending beyond the closing of the transactions.

Table 16 - Generation revenue by contracting environment (R$ mm)

(1) M&A: Includes revenue from assets in which AXIA Energia’s ownership interest has changed over the past 12 months.

(2) Energy sales related to the 12th and 13th Existing Energy Auctions (LEN) of the Tucuruí HPP, resulting from the extension of the concession term through the signing of a contract in the Regulated Contracting Environment (ACR), following the renegotiation of hydrological risk for electricity generation, as per ANEEL Ruling No. 1,395, dated May 20, 2019. The revenues refer to the period from July 12, 2024, to August 30, 2024. This event, which affected only 3Q24—with no equivalent effect in 3Q25—generated a sold volume of 1,872 MWm, recognized revenue of R$ 1,327 million, and an average price of R$ 321/MWh.

(3) Short-term market: the Brazilian electric energy trading chamber (CCEE).

(4) Main effect: recognition of a negative amount of R$ 26 million, related to adjustments in the value of thermal power plant sale transactions. This effect refers to obligations and rights with maturities extending beyond the completion of the transactions and is treated as a non-recurring adjustment to gross revenue in the period.

(5) The differences between IFRS and regulatory revenues in 2Q25, 3Q24 and 3Q25 refer to energy sold and unpaid for by Amazonas Energia, which was not recognized as revenue under IFRS accounting, but recorded under regulatory accounting, where it was fully provisioned.

Regulatory Margin from Generation

The contribution margin from generation reflects the value added by this segment’s results, considering energy trading and directly related costs, and excluding Personnel, Materials, Services, and Other expenses.

The contribution of generation to the results decreased to R$ 2,815 million in 3Q25 from R$ 3,454 million in 3Q24, which is mainly explained by the sale of the Amazonas thermal power plants in May 2025 and the lower volume of available energy due to the GSF (Generation Scaling Factor), which fell to 64.9% in 3Q25 from 79.1% in 3Q24. In unit terms, the margin by volume of available energy (energy resource) decreased to R$ 91/MWh in 3Q25 from R$ 96/MWh in 3Q24.

It is worth noting that, when excluding the thermal power plant results (Table 18), the unit contribution margin rose to R$ 93/MWh in 3Q25 from R$ 86/MWh in 3Q24, while energy resources fell to 13,819 MWm from 15,368 MWm, reflecting the drop in the GSF mentioned above.

Table 17 - Generation - adjusted contribution margin, regulatory (R$ mm)

Table 18 - Generation, ex thermal power plants - adjusted contribution margin, regulatory (R$ mm)

(1) Does not consider the accounting elimination effect of charges paid to the Company's own transmission segment.

(2) CCC: Conta de Consumo de Combustíveis, or Fuel Consumption Account, is responsible for management of payments

made by distribution and transmission companies to subsidize the costs of generators serving Isolated Systems.

(3) RHR: Renegotiation of Hydrological Risk

(4) Others: association contributions (CCEE and ONS) and other costs.

(5) Includes own resources and structural purchases, taking into account contracts with a supply duration longer than 12 months.

Table 19 - Generation - ajusted contribution margin, regulatory - by contracting environment (R$ mm)

(1) Does not consider the accounting elimination effect of charges paid to the Company's own transmission segment.

(2) Net of CCC: Conta de Consumo de Combustíveis, or Fuel Consumption Account, is responsible for management of payments

made by distribution and transmission companies to subsidize the costs of generators serving Isolated Systems.

(3) RHR: Renegotiation of Hydrological Risk

(4) Others: association contributions (CCEE and ONS) and other costs.

(5) Includes own resources and structural purchases, considering contracts with a supply term longer than 12 months.

The contribution margin of energy traded in the Free Contracting Market and settled in the Short Term Market increased to R$ 86/MWh in 3Q25 from R$ 48/MWh in 3Q24, considering the resources available for allocation in both environments.

Available resources increased due to the combined effect of volume released by the gradual phasing out of legacy contracts (decotization) and absence, this year, of the additional sale related to the Tucuruí HPP contract extension. These factors more than offset the lower GSF, which fell to 64.9% in 3Q25 from 79.1% in 3Q24.

The contribution in financial volume increased to R$ 1,556 million in 3Q25 from R$ 701 million in 3Q24, with higher revenue more than offsetting the increased expenses related to energy purchases, as a result of the energy trading strategy in the quarter.

8.3.      Transmission Segment

Regulatory Margin from Transmission

Net transmission revenue comprises gross revenue and its respective deductions and, for management purposes, represents the contribution margin of this segment.

Gross transmission revenue is based on the Allowed Annual Revenue (RAP) and the Adjustment Portion (PA) approved by ANEEL for the current tariff cycle, 2025/2026 (from July 1, 2025, to June 30, 2026). It is worth noting that the PA of the current tariff cycle is a contractual mechanism established by the regulator to compensate for any deficit or surplus between the revenue billed and the RAP approved in the previous cycle.

In addition, gross revenue includes:

(a) taxes and charges that are not part of the RAP (gross-up);

(b) discounts for unavailability;

(c) additional RAP related to new facilities that entered into operation after the approval; and

(d) pass-through items, which are offset in the following cycle through the PA.

Accounting eliminations related to transmission system usage charges paid by AXIA Energia’s generation companies to the Group’s own transmission subsidiaries are not considered. Deductions include taxes (PIS/COFINS, ICMS, and ISS) and sector charges (CDE, PROINFA, TFSEE, R&D, and RGR).

Net regulatory transmission revenue was R$ 4,187 million, up 8.5% YoY, mainly reflecting the lower PA in the current tariff cycle, primarily explained by:

(a) the repositioning of RBSE's financial component;

(b) the review of resources linked to the 2023 Periodic Tariff Review (RTP); and

(c) the addition of RAP from reinforcement and improvement projects authorized by the regulator.

Transmission auction No. 4/2025: winning bid of lots 6A, 6B, 7A and 7B, with RAP of R$ 138.74 million and CAPEX projected by ANEEL of R$ 1.63 billion, attesting to AXIA Energia's competitiveness and efficiency.

Further details and explanations are available in the "Modeling Support - Transmission" spreadsheet, located in the Results Center on the Company's Investor Relations website, including an analysis of the transmission revenue and a breakdown of the Adjustment Portion (PA).

Table 20 - Transmission - adjusted contribution margin, regulatory (R$ mm)

(1) RAP and PA: considers 1/4 of the amounts approved for the tariff cycle in effect during the quarter, and proportional amounts accumulated throughout the year.

(2) Considers (a) PIS/COFINS and (b) CDE/Proinfa. Both are pass-through costs, and AXIA Energia collects these amounts from consumers.

(3) Discount associated with Variable Portion (PV), suspension of Base Payment (PB)

due to unavailability, and pending items in Release Terms (TL).

(4) Items for which transmission companies act only as collection agents, and which will be deducted in PA in the following tariff cycle.

This involves differences between the approved RAP and billing by ONS related to cost-sharing of advances, as well

as the receipt of CDE Fund resources (via CCEE) for amounts not collected due to discounts applied on tariffs.

(5) Other mismatches in relation to the approved RAP for the current tariff cycle, such as (a) mismatch

between Transmission and Distribution Annual Adjustments, (b) complementary AVCs associated with the termination of

Transmission System Usage Agreements (CUST) by generators, etc.

(6) Does not consider the accounting elimination effect of charges paid to the Company's own transmission segment.

Eliminations: transactions that occur between companies of the same group, i.e., AXIA Energia companies.

These refer to transmission system usage charges paid by AXIA Energia generation companies to AXIA Energia transmission companies,

which receive them in the form of RAP. For consolidation purposes, these amounts are eliminated from

transmission revenue and generation usage cost.

(7) Sector Charges includes: RGR, R&D, TFSEE, CDE, and Proinfa.

8.4.      Operating Costs and Expenses - IFRS

Table 21 - Operating costs and expenses (R$ mm)

Energy purchased for resale, charges on the use of electricity grid, fuel for electricity production, and construction costs comprise the generation and transmission margins. The explanation of the remaining lines, including PMSO (Personnel, Materials, Services, and Other), is provided below.

Personnel, Material, Services and Others

(a) R$ 118 million from workforce reduction,

(b) R$ 64 million reflecting the capitalization of personnel costs, more aligned with the increased level of investments, and

(c) R$ 34 million from efficiency gains driven by team restructuring, new hiring models, and increased process centralization.

These effects were partially offset by new hires, which increased expenses by R$ 37 million.

(a) R$ 32 million with VDPs,

(b) R$ 29 million related to FGTS fine linked to terminations, and

(c) R$ 21 million with severance costs.

For more details on PMSO, including a breakdown by company and by nature of other costs and expenses, please refer to Appendix 2 - PMSO Breakdown.

Table 22 - Detailed IFRS PMSO (R$ mm)

* TPP: Thermal Power Plants. PMSO of thermal plants sold to Âmbar.For 2Q25, considers amounts for the Santa Cruz Thermal Power Plant for the full quarter.

For the other plants, whose sale was completed on May 15, 2025, amounts are considered up to that date.

** Other operating costs, related to generation operations: GSF insurance, association contributions, and other items.

Regulatory Remeasurement and Asset Disposal Result

Operating Provisions

Table 23 - Operating provisions - IFRS (R$ mm)

Positive values in the table above indicate reversal of provision.

* Primarily Includes impairment and RGR refunds.

(a) provisions recognized in 3Q25 related to cases of various natures, including civil, labor, and regulatory matters; and

(b) monetary restatement, which contributed an expense of R$ 153 million in 3Q25, compared to R$ 270 million in 3Q24.

8.5.      Equity Holdings - IFRS

The main highlights of equity income were as follows:

Table 24 - Equity holdings (R$ mm)

(1) 3Q25 income was not recognized following the signing of the agreement for the sale of the company’s stake.

(2) SPE: special purpose entities.

(3) Includes movements from amounts recognized in the balance sheet of affiliated companies measured at fair value/cost.

8.6.      Financial Result - IFRS

Table 25 - Financial result (R$ mm)

(1) These obligations were established by Law 14,182/21 (Privatization of Eletrobras, now AXIA Energia) as a condition for obtaining new concession grants for power generation for an additional 30 years. The charges were calculated based on data published in CNPE Resolution 015/2021, considering (a) the present value of the obligation; (b) the future payment flow; and (c) the payment term.

The main variations this quarter were:

8.7.      Current and Deferred Taxes - IFRS

There were no events worth highlighting in the tax line in 3Q25.

Table 26 - Income tax and social contribution (R$ mm)

(1) AXIA Energia and CGT Eletrosul in 2Q24. At the Holding level, R$1,074 million in tax credits were recognized, stemming from tax loss carryforwards accumulated by AXIA Energia, following a reassessment of taxable income due to the merger with Furnas. At CGT Eletrosul, R$292.4 million were reversed, based on a revised expectation regarding the completion of the operations required to utilize the tax credit generated by the sale of the Candiota thermal power plant.

(2) Deferred Tax recognized in 2Q25 relative to the Regulatory Remeasurement, due to changes in the payment schedule of the RBSE financial component for contracts extended under Law 12,783/2013, as approved by ANEEL’s Board at its 20th Ordinary Public Meeting held on June 10, 2025, affecting the 2025–26 to 2027–28 cycles.

9.              OPERATIONAL PERFORMANCE

9.1.      Generation Segment

Generation Assets

The Company had 82 plants, including 47 hydroelectric, 33 wind, 1 thermal and 1 solar in 3Q25, considering corporate ventures, shared ownership and stakes via SPEs. Compared to 2Q25, the decrease of six assets was primarily due to the transfer of ownership of thermal power plants held by Eletronorte. Additionally, the period reflected the acquisition of the Colíder HPP and the transfer of the Gov. Jayme Canet HPP from CGT Eletrosul.

Portfolio installed capacity reached 44,368 MW in 3Q25, with 99% generated from clean sources with low greenhouse gas emissions, representing 17% of Brazil's total installed capacity.

Table 27 - Generation assets

Total energy generated by AXIA Energia fell by 7.6% YoY in 3Q25.

Chart 4 - AXIA Energia - net energy generation (GWh)

System Data – Installed Capacity and Generation

Brazil's installed capacity was 258,111.84 MW in 3Q25.

Chart 5 - Brazil’s installed capacity - by source

Source: ANEEL's Generation Information System (SIGA)

Chart 6 - Generated energy SIN - national interconnected system (GWh)

Source: Operating Results 01/01 to 9/30/2025 from the National Operator of the Electric System (ONS)

System Data – Energy Market

Table 28 - PLD

Chart 7 - GSF (%)

Chart 8 - Historical average of affluent natural energy (ENA) - SIN (%)

During the dry season, 3Q25 recorded ENAs below the historical average, with recovery observed only in the Southern submarket in September.

Chart 9 - Energy stored in reservoirs (EAR) - SIN (%)

The Brazilian Interconnected System (SIN) ended the quarter with the level of energy stored in reservoirs at 55%, more than 6% higher than in the same period last year. The highlight was the Northern submarket at 82.4%, 7% above the highest level of the last five years.

9.2.      Transmission Segment

The Company ended 3Q25 with 74.8 thousand km of transmission lines, compared to 74.0 thousand km in 3Q24. There were also 412 substations, being 296 owned and 116 operated by third parties.

Table 29 - Transmission lines (km)

(1) Includes TMT (100%) and VSB (100%).

(2) Partnerships consider extensions proportional to the capital invested by AXIA Energia Companies in the venture.

9.3.      ESG

Table 30 - ESG KPIs 3Q25

The values presented are preliminary and not assured, and may be adjusted based on data collection, verification and updating processes.

(1) The reduction in emissions is primarily due to the removal of coal-fired thermoelectric generation from the Company’s energy matrix.

(2) Reduction was due to departures connected to the VDPs.

(3) The percentage of complaints handled remains within the parameters established by the target.

10.          APPENDIX

10.1.  Appendix 1 - Generation and Transmission Revenue IFRS

Generation revenue comprises:

(a) revenue from supply to non-end consumers — distributors, traders, and generators — under contracts in the Regulated Contracting Environment (ACR) and the Free Contracting Environment (ACL);

(b) revenue from supply to end consumers — industrial and commercial clients — under contracts exclusively in the ACL;

(c) revenue from the CCEE, through settlements in the Short Term Market (MCP); and

(d) revenue from operation and maintenance, representing remuneration for energy sold under the quota regime.

Table 31 - Generation operating revenue (R$ mm)

Transmission revenue comprises:

(a) operation and maintenance (O&M) revenue, related to the operation and maintenance of assets;

(b) construction revenue, linked to investments made (appropriated and allocated) in ongoing projects; and

(c) contractual (financial) revenue, associated with the application of inflation indices to the asset balances of each concession contract.

Table 32 - Transmission operating revenue (R$ mm)

10.2.  Appendix 2 - PMSO Breakdown

Table 33 - PMSO 3Q25 (R$ mm)

Table 34 - PMSO 3Q24 (R$ mm)

Table 35 - Other costs and expenses (R$ mm)

10.3.  Appendix 3 - Financing and Loans Granted (Receivables)

Chart 10 - Receivables (R$ billion)

Does not include ECL of R$ 3,989 million and current liabilities.

10.4.  Appendix 4 - Accounting Statements

Table 36 - Balance sheet (R$ thousand)

Table 37 - Income statement (R$ thousand)

Table 38 - Cash flow statement (R$ thousand)