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 May, 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____

ELETROBRAS RELEASES 1ST QUARTER 2025 RESULTS

Highlights 1Q25

(a) R$ 96 million related to Voluntary Dismissal Plans (VDPs);

(b) R$ 31 million and R$ 22 million in severance costs for 1Q25 and 4Q24, respectively;

(c) R$ 42 million in legal consulting expenses related to the contingency reduction strategy.

(a) higher generation revenue;

(b) lower costs and expenses with personnel, materials, services and others;

(c) lower provisions recognized in the quarter;

(d) increased contribution from equity results.

These effects were offset by lower transmission revenue and higher costs with energy purchased for resale.

Table 1 - Adjustments on Regulatory EBITDA (R$ mm)

MAIN FINANCIAL AND OPERATING INDICATORS

Table 2 - 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 Eletrobras plants; (c) the AC increase at Santa Cruz TPP due to the completion of the Combined Cycle, following ANEEL Order 481 of Feb 23, 2023 that authorized the start of commercial operations for a new generating unit at the plant.

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

Table 3 - Financial Highlights

HIGHLIGHTS OF CONSOLIDATED RESULTS

1.             CONSOLIDATED RESULT | IFRS AND REGULATORY

Table 4 - Income Statement IFRS (R$ mm)

Table 5 - Regulatory IS (R$ mm)

2.             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.

Additional explanations are provided in Appendix 4 of this report to support a better understanding of the topics.

A detailed reconciliation is also available in the ‘Regulatory and Corporate Income Statement Reconciliation’ spreadsheet, accessible on Company's IR website in the Results Center, under ‘Attachments’.

Table 6 - Regulatory IS x IFRS IS(R$ mm)

Adjustments of non-recurring events

The following adjustments are based on events deemed non-recurring:

3.             ADJUSTED EBITDA

Adjusted Regulatory EBITDA

In 1Q25, Adjusted Regulatory EBITDA totaled R$ 5,377 million, down R$ 229 million compared to 1Q24, reflecting lower transmission revenue, higher costs for energy purchased for resale, and a reduced contribution from equity income—partially offset by higher generation revenue, lower PMSO expenses, and a reduced volume of provisions recognized during the quarter.

It is worth noting that the decrease in EBITDA can also be explained by a negative financial result in the short-term market (CCEE), due to the higher settlement volume, which had a negative net effect mainly caused by price differences between submarkets. The increase in free market trading reflects a strategy that favored higher contracting in 1Q25, rather than maintaining uncontracted energy volumes for the rest of the year.

It is important to highlight that this portfolio optimization strategy is based on a balanced assessment of supply and demand risks under prospective scenarios throughout the year. These assumptions are continuously reviewed and recalibrated.

Table 7 - Adjusted Regulatory EBITDA (R$ mm)

(1) Recognizes the amount of R$ 432 million in 1Q24 related to revenue from Amazonas Energia. Due to default, these balances are also fully recognized in operating provisions. In 4Q24 and 1Q25, the revenue from thermal plants was recognized without any corresponding provision. As part of HPP Balbina's revenue remained—and continues to remain—in default, the amounts of R$ 32 million in 4Q24 and R$ 56 million in 1Q25 were provisioned.

Generation revenue was R$ 7,023 million in 1Q25, up R$ 658 million compared to 1Q24, mainly due to higher revenues in the free contracting environment (ACL) of R$ 753 million and in the regulated contracting environment (ACR) of R$ 263 million, which were partially offset by lower revenues from plants under the quota regime of R$ 268 million, and from the short-term market of R$ 89 million.

The increase in revenue was accompanied by higher costs associated with generation, of R$ 762 million, reaching R$ 3,152 million in 1Q25. Of note were expenses with energy purchased for resale and fuel for electricity production, which went up by R$ 830 million and R$ 54 million, respectively, while expenses with network usage charges fell by R$ 123 million.

Still on generation, it is also worth noting the progress in receivables related to energy sold by Eletrobras thermal plants and by Balbina HPP to Amazonas Energia (AmE) following the resumption of its recognition in 3Q24. In 1Q25 the regulatory gross revenue from energy sold by thermal plants and Balbina HPP totaled R$1.3 billion. Approximately 88% of the total was billed under the Reserve Energy Contract (CER) and was received through the Reserve Energy Charge. It is worth noting that in 1Q25 there is no more volume to be converted into CER. The remaining 12%, billed to AmE is divided into two groups:

(a) Sales contracts from thermal plants classified as Independent Power Producers, which were paid by AmE (3% of the total); and

(b) Energy sold by Balbina HPP (9% of the total).

The only unpaid portion in the quarter, of R$ 56 million, corresponds to approximately 48% of the energy sold by Balbina HPP, and it accounts for the difference between regulatory and IFRS gross revenue. In the IFRS accounting, this portion was not recognized as revenue, whereas in the regulatory accounting, it was recognized and fully provisioned.

Table 8 - Amazonas Energia (R$ mm)

Transmission revenue was R$ 4,423 million in 1Q25, down R$ 687 million from 1Q24, mainly driven by reductions in Annual Permitted Revenue (RAP) and the Adjustment Portion (PA), revised as part of the Periodic Tariff Adjustment and Annual Adjustment processes for the 2024-2025 regulatory cycle, which started in July 2024.

Personnel, Material, Services and Others (PMSO) went down by R$ 134 million YoY, totaling R$ 1,473 million in 1Q25. This decrease is primarily driven by the gains from various initiatives implemented by the Company to improve staff efficiency, as well as adjustments to processes and the organizational structure.

Provisions decreased R$ 467 million, reaching R$ 77 million in 1Q25, from R$ 544 million in 1Q24 . This reduction essentially reflects the sharp decline in defaults on energy sales to Amazonas Energia, from R$432 million in 1Q24 to R$56 million in 1Q25, given that in 2024, energy sold by both the thermal plants and Balbina HPP was in default, whereas in 2025, defaults were limited to only the portion of energy sold by Balbina.

Finally, equity income represented a YoY improvement of R$ 75 million, reaching R$ 371 million in 1Q25.

Adjusted IFRS EBITDA

Adjusted IFRS EBITDA reached R$ 4,416 million in 1Q25, down -2.5% from 1Q24.

The increase in transmission and generation revenues, along with reductions in PMSO and provision expenses, was not enough to offset the increase in expenses with energy purchased for resale and the lower contribution from equity income.

Table 9 - Adjusted IFRS EBITDA (R$ mm)

The table detailing the EBITDA calculation, in accordance with CVM Resolution 156/2022, is presented in Appendix 5 of this document.

4.             ENERGY TRADING

Eletrobras companies sold 39.0 TWh of energy in 1Q25, up 20.9% compared to the 32.3 TWh traded in 1Q24. 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 Special Purpose Entities - SPEs, consolidated: HPPs Teles Pires (starting Oct/23), Baguari (starting Oct/23), Retiro Baixo (starting Nov/23), and Santo Antônio (starting Nov/23).

Table 10 - Energy Balance 1Q25 (aMW)

Contracts signed until 3/31/2025.

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

Table 11 - Assured Capacity Quotas of Hydroelectric Power Plants (aMW)

5.             INVESTMENTS AND EXPANSION PROJECTS

Investments in 1Q25 totaled R$ 912 million, with R$ 655 million allocated to transmission, R$ 167 million to generation, R$ 43 million to infrastructure and R$ 47 million to the environmental area.

The amount invested in infrastructure was allocated as follows: 53% to socio-environmental initiatives, 20% to IT, 17% to real estate, and 10% to equipment and vehicles. In the socio-environmental area, key highlights included investments related to the maintenance of operating licenses for power plants and substations, seismological monitoring, water quality and wildlife monitoring, as well as land compensation.

Table 12 - Investments (R$ mm)

Generation

Investments in generation totaled R$ 167 million in 1Q25, compared to R$ 502 million in 1Q24.

The reduction is mainly explained by decreased expenses associated with the expansion of CGT Eletrosul, as the Coxilha Negra Wind Farm project nears completion .

In 1Q25, main expenditures were allocated to

Transmission

Investments in transmission totaled R$ 655 million in 1Q25, mainly in reinforcements and improvements (R&I) that reached R$ 596 million, a stable level compared to 1Q24. Investments in expansions reached R$ 54 million, reflecting the progress of activities in transmission lines and substations related to lots won in auctions in recent years.

In 1Q25, expenditures were distributed as follows:

Expansion Projects - Transmission

Large-Scale Projects

Small-Scale Projects

Expansion Projects - Generation

Two projects are currently under construction and, once completed, will add approximately 330 MW to Eletrobras’ installed capacity.

Coxilha Negra Wind Farm (302.4 MW capacity, located in Rio Grande do Sul state)

3 Referring to reinforcements, improvements and auction projects. Considers projects registered in ANEEL's Transmission Management System (SIGET). Projects are included when added to the system and excluded when they are canceled or enter commercial operation. The 240 projects will add approximately 2,400 km of transmission lines and 12,000 MVA in substations.

4 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.

Casa Nova B Wind Farm (27 MW capacity, located in Bahia state)

6.             INDEBTEDNESS

Net debt totaled R$ 39.3 billion in 1Q25, up R$ 1.60 billion from 4Q24 and down R$ 1.56 billion from 1Q24. The Net Debt/Adjusted Regulatory EBITDA LTM ratio reached 1.7x in 1Q25, 1.6x in 4Q24 and 1.8x in 1Q24.

As a result of liability management and a 200 bps increase in the Brazilian basic interest rate (Selic), the Company's average debt maturity was extended by 12.6 months, while the total average cost decreased to CDI + 0.15% p.a. in 1Q25 from CDI + 0.93% p.a. in 1Q24.

Deserves highlight the maturity in February of the 2025 Bond, with a principal amount of US$ 500 million. On the funding side, the highlight of the quarter was the issuance of bank debt by Eletronorte in the amount of R$ 500 million (equivalent to US$86.5 million), to strengthen cash position. The issuance carries a SOFR + 0.45% rate, swapped to CDI + 0.44% p.a., with maturity on March 1, 2026.

Table 15 - Net Debt (R$ mm)

Chart 1 - Loans and Financing Payable (R$ billion)

Table 16 - Gross Debt Breakdown

*It is important to note that the Company has carried out exchange rate hedge operations for certain foreign currency debts. The data below presents these debts along with their respective equivalent rates (post-hedge) linked to the CDI:

Bonds 2025 - 97.41% of CDI

Bonds 2030 - CDI + 1.70% p.a.

Bonds 2035 - 122.59% of CDI

Citibank - CDI + 0.19% to 1.70% p.a.

Itaú - CDI + 0.30% p.a.

** Exposure to BNDES only considers contracts under the BNDES direct line.

7.             COMPULSORY LOAN

Eletrobras has implemented measures to mitigate risks associated with legal proceedings related to compulsory loans on electricity, which involve the monetary adjustment of book-entry credits.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:

Thus, as from 3Q22, when negotiations began, the provision inventory related to this set of lawsuits fell by R$ 12.7 billion, from R$25.8 billion to the current R$ 13.1 billion, even considering the accumulated monetary restatement of R$2.5 billion in the period. In addition, the agreements signed also allowed for the elimination of R$8.5 billion in legal risks considered "off balance", of which R$ 791 million classified as possible and R$ 7.7 billion as remote. These reductions are in line with the Company's strategy of reducing its legacy legal liabilities.

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

8.             CASH FLOW

In 1Q25, funds generated by operating activities reached R$ 6.0 billion, up R$ 2.7 billion from the R$ 3.3 billion recorded in 1Q24. It is worth highlighting this quarter the receipt of approximately R$ 1.0 billion—related to energy sold by thermal plants to Amazonas Energia in 1Q25, portion that had been in default in 1Q24.

Operating cash generation in 1Q25 was allocated to:

Table 17 - Cash Flow (R$ bn)

*Excludes generation contributions.

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

FINANCIAL AND OPERATING RESULTS ANALYSIS

9.             FINANCIAL PERFORMANCE

9.1.        Operating Revenue

Regulatory Generation Revenue

Adjusted regulatory revenue was R$ 7,023 million in 1Q25, R$ 56 million lower than adjusted IFRS generation revenue, reflecting the different treatment of the portion of revenue from Amazonas Energia related to outstanding unpaid amounts for energy sold by Balbina HPP.

Generation Revenue by Contracting Environment

When comparing 1Q25 x 1Q24 x 4Q24 there are no M&A effects.

Excluding the portion from construction, regulatory adjusted revenue from energy sales across all contracting environments totaled R$ 7,023 million in 1Q25, reflecting an YoY increase of R$ 658 million.

The positive highlights were the respective increases of R$ 753 million and R$ 263 million million in the free contracting and regulated market environments. On the other hand, there was a R$ 268 million reduction in revenue from O&M energy sales from plants under the quota regime. Finally, revenue in the short-term market fell by R$ 89 million, reflecting the lower volume settled in this environment.

In 1Q25, revenue increased 10.3% compared to 1Q24, due to a 10.4% increase in average price and a 1.0% increase in volume.

The 211 aMW increase in total volume is mainly explained by increases of 2,717 aMW in the free market and 401 aMW in the regulated market, more than offsetting the reductions of 1,485 aMW in energy settled in the short-term market and 1,422 aMW of energy traded under the quota regime.

Table 18 - Generation Revenue by Contracting Environment (R$ mm)

(1) Short-term market: Electricity Trading Chamber (CCEE)

(2) Construction Revenues

(3) The R$ 56 million in 1Q25 and R$ 32 million in 4Q24 refer to energy sold by the HPP Balbina, but defaulted by Amazonas Energia. As a result, the amount is not recognized as revenue under IFRS accounting, but is recorded under the regulatory accounting, where it is fully provisioned. In 1Q24, the R$ 432 million refers to all energy sold to the same customer—not only by Balbina HPP, but also by the thermal plants.

(4) M&A: includes revenue from assets in which Eletrobras' stake has changed over the last 12 months.

Regulatory Transmission Revenue

Regulatory transmission revenue was R$ 4,423 million, down 13.4% from 1Q24. The decrease reflects the approval, in July 2024, of the 2023 periodic tariff review (RTP), which were postponed to 2024, with a particular focus on the revenue review for concession contracts extended under Law No. 12,783/2013.

It is worth noting that the eliminations, both in regulatory and IFRS revenue, refer to the portion of transmission system usage charges paid by Eletrobras’ generation companies to the Group’s own transmission companies, which receive them as RAP. For consolidation purposes, these amounts are eliminated from transmission revenue and from the cost of transmission system charges in generation. The IFRS accounting considers the portion of revenue related to operation and maintenance (O&M), whereas under regulatory accounting, the elimination reflects the RAP.

5 According to ANEEL Resolutions No. 3,068/2022 (2022-2023 cycle) and No. 3,225/2023 (2023-2024 cycle), impacting Eletronorte, Chesf and Furnas.

Table 19 - Quarterly IFRS vs. Regulatory Revenue (R$ mm)6

Chart 3 - Reconciliation RAP and Transmission Revenue 1Q25 (R$ mm)

Regulatory Transmission Revenue: Approved RAP x Gross Revenue

6 For more information on Eletrobras Holding's Corporate Structure, refer to Appendix 3 of this report.

(i) Between Annual Adjustment of Transmission and Distribution: Associated with the timing mismatch between the amounts approved for Other Transmission Facilities (DIT) for exclusive use in the Annual RAP Adjustment for transmission companies (ANEEL Resolution No. 3,348/2024) and the revenue amounts approved in the Annual Adjustments of the distribution companies, which occur at different times. In 1Q25, this difference totaled approximately R$ 40 million.

(ii) Border Network Difference: Related to the difference between the RAP amounts approved for the Basic Border Network and Other Transmission Facilities (DIT) for shared use in the Annual RAP Adjustment of the transmission companies for the 2024/2025 cycle, and the billing amounts reflected in the AVCs issued by ONS. These adjustments will be incorporated into the Adjustment Portion of the following cycle. In 1Q25, this difference totaled approximately R$ 64 million.

(iii) Other Transmission Facilities (DIT) Difference for Exclusive Use of Itaipu: Refers to the discrepancy between the approved RAP for Other Transmission Facilities (DIT) for Itaipu’s exclusive use and the monthly amount collected based on the power and tariff approved by ANEEL. For each subsequent calendar year, ANEEL publishes the contracted power amounts for Itaipu in a specific Regulatory Resolution, while the monthly tariff for electricity transportation from Itaipu Binacional is published for the Transmission tariff cycle. As a result, an adjustment is required to account for variations in contracted power, arising from the timing mismatch between the calendar year and the tariff cycle. This adjustment is considered in the Adjustment Portion of the following cycle. In 1Q25, this mismatch totaled approximately -R$ 11 million.

RAP Changes for Extended and Tendered Contracts, as approved by ANEEL Resolutions 3,343/2024 and 3,344/2024

On April 4 and 24, 2025, ANEEL published Rulings No. 920/2025 and No. 1,228/2025, respectively, approving the revised results of the Periodic Review for contracts with a review date in July 2024, as well as the 2nd Periodic Review of contracts renewed under Law No. 12,783/2013. The effects of these approvals will be fully reflected in the 2025–2026 cycle.

As a result, there was a reduction of 0.01%—equivalent to just R$ 14,000—when comparing the total approved RAP and Adjustment Portion to the amounts set forth in ANEEL Resolution No. 3,343/2024 for the tendered contracts that were revised. For the renewed contracts, the reduction was 5.48%, or R$ 371.9 million, compared to the total approved RAP and Adjustment Portion established in ANEEL Resolution No. 3,344/2024. Additional details on the changes, including a breakdown by contract, are provided in Appendices 9 and 10.

9.2.        Operating Costs and Expenses

Table 20 - Operating Costs and Expenses (R$ mm)

PMSO - Personnel, Material, Services and Others

Personnel: adjusted balance of R$ 802 million in 1Q25, down 15% from R$ 945 million in 1Q24, with the main effects being:

Non-recurring effects: R$ 150 million, of which: (a) R$ 96 million with VDPs, (b) R$ 31 million with severance costs, and (c) R$ 22 million with severance indemnity fund (FGTS) fines linked to terminations.

Material: adjusted balance of R$ 52 million in 1Q25, up R$ 6 million when compared to R$ 46 million recorded in 1Q24. The variation reflects higher operational maintenance expenses of R$ 15 million, partially offset by savings of R$ 9 million related to contract optimization with suppliers.

There were no non-recurring effects in the quarter.

Services: adjusted balance of R$ 396 million in 1Q25, representing a 10% decrease compared to R$ 439 million in 1Q24. The main highlights for a drop of R$ 43 million were:

Non-recurring effects: R$42 million for legal consulting related to the contingency reduction strategy.

Others: adjusted balance of R$ 217 million in 1Q25, up R$ 52 million compared to 1Q24, mainly reflecting the R$ 34 million increase in expenses related to fines, court rulings, legal costs, as well as other losses.

There were no non-recurring effects in the quarter.

Table 21 - PMSO 1Q25 (R$ mm)7

Table 22 - PMSO 1Q24 (R$ mm)

7 For more information on the Composition of Eletrobras Holding, see Appendix 3 .

Table 23 - PMSO IFRS (R$ mm)

Table 24 - Other Costs and Expenses (R$ mm)

Operating Provisions

Table 25 - Operating Provisions - IFRS (R$ mm)

Positive values in the table above indicate reversal of provision.

* Primarily Includes impairment and RGR refunds.

9.3.        Equity Holdings

Equity income had two highlights this quarter:

Table 26 - Equity Holdings (R$ mm)

9.4.        Financial Results

Table 27 - Financial Result (R$ mm)

(1) These obligations were established by Law 14,182/21 (Eletrobras Privatization) as a condition for obtaining new concession grants for electricity 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. See Table 28 for more details.

Adjusted financial result was negative by R$ 3,321 million in 1Q25, compared to negative R$ 2,781 million in 1Q24. The main variations in this quarter were:

Table 28 - CDE Charges and Projects - Law 14.182/2021 (R$ mm)

9.5.        Current and Deferred Taxes

Adjusted income tax and social contributions amounted to -R$ 65 million in 1Q25, compared to -R$ 305 million in 1Q24. There were no adjustments to the tax line in either period.

Table 29 - Income Tax and Social Contribution (R$ mm)

¹ Holding and CGT Eletrosul

² Deferred Income Tax recognized in 4Q24 on the Regulatory Remeasurement of transmission contracts in the Holding following the Furnas merger.

10.         OPERATING PERFORMANCE

10.1.   Generation Segment

Generation Assets

The Company had 88 plants, including 47 hydroelectric, 7 thermal, 33 wind and 1 solar in 1Q25, considering corporate ventures, shared ownership and stakes via SPEs. Compared to 4Q24, the increase of one asset was due to the commercial operation of the Coxilha Negra 4 wind farm under CGT Eletrosul

The installed capacity of the portfolio reached 44,359.12 MW in 1Q25, with 97% generated from clean sources with low greenhouse gas emissions, representing 18% of Brazil's total installed capacity.

Table 30 - Generation Assets

In 1Q25,the total energy generation by Eletrobras increased by 1.1% compared to 1Q24.

Chart 4 - Eletrobras - Net Energy Generation (GWh)

System Data - Installed Capacity and Generation

In 1Q25, Brazil's installed capacity was 248,710.12 MW.

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 3/31/2025 from the National Operator of the Electric System (ONS)

System Data - Energy Market

Table 31 - PLD

Chart 7 - GSF (%)

Chart 8 - Historical Average of Affluent Natural Energy (ENA) - SIN (%)

1Q25 was marked by low hydroelectric generation in the system, particularly in March, which recorded the fourth worst performance in the historical series.

Chart 9 - Energy Stored in Reservoirs - SIN (%)

The level of Energy Stored in Reservoirs was at 69.4% in 1Q25, above the midpoint of the range based on historical data from 2020 to 2024.

10.2.   Transmission Segment

The Company ended 1Q25 with 74.1 thousand km of transmission lines, of which 67.3 thousand km were owned and 6.8 thousand km operated through partnerships, compared to 73.8 thousand km in 1Q24 (66.5 thousand km owned and 7.3 thousand km in partnership).

There were also 405 substations in 1Q25, including 293 owned and 112 operated by third parties.

Table 32 - Transmission Lines (Km)8

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

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

10.3.   ESG

Table 33 - ESG KPIs 1Q25

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

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

8 For more information on Eletrobras Holding's Corporate Structure, refer to Appendix 3 in this report.

11.         APPENDIX

11.1.   Appendix 1 - Accounting Statements

Table 34 - Balance Sheet (R$ Thousand)

Table 35 - Income Statement (R$ Thousand)

Table 36 - Cash Flow Statement (R$ Thousand)

11.2.   Appendix 2 - Statement on Thermal Power Plants Sale

On June 10, 2024, Eletrobras signed an agreement with Âmbar Energia/J&F Group to sell its thermoelectric portfolio for R$ 4.7 billion, including R$ 1.2 billion in earn-out. J&F also immediately and fully assumed the credit risk of the energy contracts in this portfolio.

On June 12, 2024, Provisional Measure No. 1,232 was published, introducing changes to the rules for isolated systems. The measure allows for a corporate transfer plan to be approved as an alternative to concession extinction, provided that ANEEL recognizes the loss of service conditions. It also modifies the rules for energy purchase and sale contracts (CCVEEs) reimbursable by the Fuel Consumption Account (CCC).

As a result, Eletronorte entered into Reserve Energy Contracts (CERs) with the Electric Energy Commercialization Chamber (CCEE), linked to specific Company power plants9. In addition, the terminations of CCVEEs for these plants, along with the Term of Withdrawal and Waiver of Rights against the Federal Government regarding energy purchases, were signed with Amazonas Distribuidora de Energia S/A before exchanging contracts for CERs.

The documents were approved sub judice in accordance with ANEEL Ruling No. 3,025, dated October 7, 2024. Eletrobras is already receiving the new CER-related payments directly from CCEE, including retroactive amounts up to June 13, 2024, the date on which the energy supply provided for in the CERs began.

Furthermore, on May 14, 2025, the partial closing of the sale of thermal plants to the J&F Group was concluded. This phase includes the thermoelectric assets of Eletronorte, which are the counterparties to the new CERs. The closing of the sale of TPP Santa Cruz (500 MW), the last remaining asset in the divested portfolio, is still pending the completion of regulatory approvals.

11.3.   Appendix 3 - Statement on Furnas Merger

In the tables detailing the main operating subsidiaries of the Eletrobras Group, the comments on results for “Eletrobras Holding” as of 3Q24 take into account the following considerations:

These seven entities were previously consolidated under Furnas.

For simplicity in comparisons between 1Q25 and 1Q24, the sum of Eletrobras Holding and consolidated Furnas, including the seven SPEs, was considered for 1Q24. This approach was adopted as the eliminations have an immaterial impact on both the operating result (revenue and EBITDA) and the financial result.

9 Aparecida, Jaraqui, Tambaqui, Cristiano Rocha, Manauara and Ponta Negra.

11.4.   Appendix 4 - Regulatory vs IFRS Income Statement

Considering the regulatory income statement versus the IFRS one, the differences in accounting treatment in both frameworks generated a positive effect of R$ 1,167 million on EBITDA and R$ 489 million on net income.

Chart 10 - EBITDA Regulatory x IFRS (R$ mm)

Chart 11 - Net Income Regulatory x IFRS (R$ mm)

The difference between regulatory and IFRS net income can also be analyzed by reorganizing the Income Statement lines. It is possible to group them according to the operational nature of the events to which they are related. This exercise consists of segmenting them into (a) transmission, (b) generation, (c) equity holdings, and (d) others—including provisions, financial result and taxes.

As a result, the entire difference between regulatory and IFRS net income is essentially explained by the specific accounting treatment applied to the transmission segment under each accounting framework, resulting in a positive effect of R$ 594 million on regulatory net income, considering the transactions of consolidated companies within this segment.

Chart 12 - Net Income Regulatory x IFRS by Segment (R$ mm)

Transmission: R$ 594 million positive effect

Chart 13 - Transmission Effects (R$ mm)

(a) In the regulatory system, revenue is recognized on a cash basis, based on the billing of transmission concessionaires. Under IFRS, revenue reflects the value of the contractual asset, which is a non-cash item.

(b) The difference in the way the network usage charge paid by Eletrobras’ generation companies to its own transmission companies is eliminated from transmission revenue, following the cash regime in the regulatory framework. In the IFRS framework, one of the non-cash portions of transmission revenue is considered: operation and maintenance revenue.

Generation: R$ 67 million negative effect

Chart 14 - Generation Effects (R$ mm)

Equity Income: R$ 3 million positive effect

Other Lines: -R$ 41 million negative effect

11.5.   Appendix 5 - EBITDA IFRS

Table 37 - Adjusted IFRS EBITDA (R$ Thousand)

11.6.   Appendix 6 - Generation Revenue IFRS

The following table presents the breakdown of the IFRS Generation Revenue, aligned with the accounting statements. The power supply for distribution companies is revenue derived from customers who are not end consumers, such as distributors, traders, and generators, covering contracts in both the free contracting (ACL) and regulated market (ACR) environments, while the power supply for end consumers is revenue that comes directly from end consumers, including industries and commercial entities, and consists exclusively of contracts in the free contracting environment (ACL).

Table 38 - Gross Revenue 1Q25 (R$ mm)

Table 39 - Gross Revenue 1Q24 (R$ mm)

11.7.   Appendix 7 - Transmission Revenue IFRS

IFRS transmission revenue was R$ 5,186 million in 1Q25, up 14% from 1Q24, recording increases of R$ 350 million in Contractual revenue, R$ 160 million in Construction revenue, and R$ 117 million in O&M revenue. O&M revenue relates to the operation and maintenance of assets in operation. Construction revenue corresponds to investments made (appropriated and allocated) in ongoing projects. Contractual (financial) revenue is derived from the application of inflation indexes to the contract asset balances of each concession.

Table 40 - Transmission Operating Revenue (R$ mm)

11.8.   Appendix 8 - Regulatory Transmission Revenue - Adjustment Portion (PA)

The Adjustment Portion (PA) of the current tariff cycle is a regulatory mechanism, as outlined in the contract, designed to compensate for revenue deficits or surpluses from the previous tariff cycle. In other words, it adjusts the difference between the amounts received and those allowed in the prior cycle, which is then offset in 12 equal monthly installments during the current cycle. The Adjustment Portion can be positive or negative, depending on each agent’s balance.

The table below presents the PA breakdown defined by ANEEL for the 2024/2025 cycle, as established in ANEEL Resolution 3,348/2024, within the scope of the Annual RAP Readjustment for the 2024/2025 cycle. Additionally, for the upcoming tariff cycles (2025/2026 to 2027/2028), the PA Reviews established by ANEEL under the RAP periodic review processes for renewed and tendered concession contracts—approved by ANEEL up to the 2024/2025 cycle—are also included.

Table 41 - Adjustment Portion (PA) - ANEEL Resolution 3,348/2024 (R$ mm)

(1) Adjustment Portion (PA) established in ANEEL Resolution No. 3,344/2024, defining the RAP Periodic Review results for Concession Contracts 057/2001, 058/2001, 061/2001, and 062/2001, extended under Law 12,783/2013, following Public Consultation (CP) ANEEL 12/2024.

(2) PA Postponement: Financial differences from postponing the RAP Periodic Review for extended concession contracts from 07/01/2023 to 07/01/2024, per Ruling No. 402/2023. PA to be offset in a single installment.

(3) Includes annuities (prepayments) for the execution of small-scale improvements related to the 2023-2024 cycle.

(4) PA Retroactive: Retroactive RAP additional installments for reinforcements and improvements undergoing their first Periodic Review (incremental basis), covering the period from commercial operation start until June 30, 2023, as per Submodule 9.7 of PRORET. Already adjusted for full-year payments related to prepayment of part of the revenue associated with executing small-scale improvements that initially had no prior revenue. To be offset in equal installments until the subsequent review in July 2028.

(5) PA Other Adjustments - RTP 2023: Adjustments based on Technical Notes No. 58/2024 and No. 103/2024-STR/ANEEL, supporting Public Consultation 12/2024. To be offset in a single installment.

(6) PA Annual Fee Improvements: Annual financial contribution for the execution of small-scale improvements to be considered as from the 2024-2025 cycle until the 2027-2028 cycle

(7) PA Calculation: Offsets differences arising from revenue deficits or surpluses in the ONS accounting process.

(8) PA Authorizations for Small-Scale Reinforcements without RAP: Covers the RAP portion from the commercial operation start date (per ONS Release Term) until June 30 of year i (June of cycle i-1), for cases where small-scale reinforcements were authorized with RAP established within the Annual RAP Adjustment.

(9) Considers only the PA of the Review approved by ANEEL for Tendered concession contracts reviewed until 2024.

11.9.   Appendix 9 - RAP's Periodic Tariff Review of tendered contracts revised in 2024

The result of the Periodic Tariff Review (RTP) of the Annual Permitted Revenue (RAP) for the Auctioned Transmission Concession Contracts reviewed in 2024 was initially established through ANEEL Resolution No. 3,343/2024, published on July 11, 2024.

On April 4, 2025, ANEEL published Ruling No. 920/2025, through which it decided to consider the administrative appeals filed against ANEEL Resolution No. 3,343/2024 and partially uphold them. The ruling approved amendments to the outcome of the RAP Periodic Review for the auctioned transmission concession contracts with a review date of July 2024, whose effects will be effectively reflected throughout the 2025–2026 cycle.

Following the analysis of the reconsideration requests, the Agency identified material errors and the need to make official corrections.

As a result of the adjustments introduced by Ruling No. 920/2025, there was a 0.01% reduction in the total value of the RAP plus the Adjustment Portion originally approved by ANEEL Resolution No. 3,343/2024, as detailed in the following tables:

Table 42 - Revised RAP and PA values for Reinforcements and Improvements, after analysis of the appeals against ReH No. 3,343/2024 (R$) – Dispatch No. 920/2025

11.10.                   Appendix 10 - 2nd RAP's Periodic Tariff Review of contracts extended by Law 12,783/2013

The second Periodic Tariff Review (RTP) of the Annual Permitted Revenue (RAP) for the transmission concession contracts extended under Law No. 12,783/2013 was originally scheduled for 2023, with a review date of July 1, 2023, but was postponed to July 1, 2024, as established by ANEEL Ruling No. 402/2023. The result of this review was published on December 7, 2024, through ANEEL Resolution No. 3,344/2024.

On April 24, 2025, ANEEL issued Ruling No. 1,228/2025, in which it acknowledged the administrative appeals filed against Resolution No. 3,344/2024 and partially granted them, approving amendments to the outcome of the Periodic Review for the RAP of the extended transmission concession contracts. The effects of these changes will be effectively reflected throughout the 2025–2026 RAP cycle.

In addition to evaluating the reconsideration requests, the Agency conducted a new calculation of the Tariff Review and identified the need for official changes.

It is worth noting that, although part of the Company’s claims were accepted—resulting in positive impacts on revenue—the final outcome of the review led to a net reduction in revenue and in the Adjustment Portion (PA), due to official changes prompted by material errors. The main variation occurred in the Economic Component of RBSE, whose revenue was reduced by approximately R$192 million, with an equivalent impact on the Adjustment Portion.

As a result of the adjustments introduced by Ruling No. 1,228/2025, there was a 2.5% reduction in the RAP and a 23.2% reduction in the Adjustment Portion originally approved by ANEEL Resolution No. 3,344/2024, as detailed in the tables below:

Table 43 - Comparison of the impact of the changes to the RAP approved by ANEEL Res. No. 3,444/2024

Table 44 - Comparison of the impact of the changes to the PA(1) approved by ANEEL Res. No. 3,444/2024

The consolidated result, reflecting the adjustments established in Ruling No. 1,228/2025, is presented in the table below:

Table 45 - Consolidated changes to the revenue approved by ANEEL Res. No. 3,444/2024

11.11.                   Appendix 11 - Financing and Loans Granted (Receivables)

Chart 15 - Receivables (R$ billion)

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

11.12.                   Appendix 12 - Result Reconciliation Regulatory vs. IFRS

Table 46 - Reconciliation IFRS vs. Regulatory (R$ Thousand)