6-K 1 axiapr4q25_6k.htm 6-K

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 February, 2026

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____

TABLE OF CONTENTS
1. CONSOLIDATED RESULT \| IFRS AND REGULATORY	8
2. ADJUSTED CONSOLIDATED RESULT \| IFRS AND REGULATORY	9
3. ENERGY TRADING	12
4. INVESTMENTS AND EXPANSION PROJECTS	12
5. INDEBTEDNESS	15
6. COMPULSORY LOAN	16
7. CASH FLOW	17
8. FINANCIAL PERFORMANCE	18
8.1. Operational and Financial Results	18
8.2. Generation Segment	20
8.3. Transmission Segment	24
8.4. Operating Costs and Expenses - IFRS	26
8.5. Equity Holdings - IFRS	30
8.6. Financial Result - IFRS	32
8.7. Current and Deferred Taxes - IFRS	33
9. OPERATIONAL PERFORMANCE	34
9.1. Generation Segment	34
9.2. Transmission Segment	37
9.3. ESG	38
10. APPENDIX	39
10.1. Appendix 1 - Generation and Transmission Revenue IFRS	39
10.2. Appendix 2 - PMSO Breakdown	40
10.3. Appendix 3 - Financing and Loans Granted (Receivables)	40
10.4. Appendix 4 - Accounting Statements	41
10.5. Appendix 5 - IFRS vs. Regulatory Reconciliation	46

AXIA ENERGIA RELEASES FOURTH QUARTER 2025 RESULTS

4Q25 Main Events

4Q25 results: The quarter reflected positive effects from energy sales, resulting in improved generation contribution margins, lower Personnel, Materials, Services, and Other (PMSO) expenses, expanded transmission margins, and reduced provision volumes. These advances evidenced the strategy of optimizing the energy portfolio, the continuous pursuit of operational efficiency, and consistent action in mitigating contingencies.

Rebranding: In October 2025, the Company announced a new chapter in its trajectory as the largest clean energy company in the Southern Hemisphere with the launch of the AXIA Energia brand, representing a future vision of a company guided by financial discipline, operational excellence, and consistent value creation.

Extinction of the Direct Action of Unconstitutionality (ADI) 7,385: On December 11, 2025, the Supreme Federal Court (STF) ratified the Settlement Agreement between the Company and the Federal Government within the Federal Administration's Mediation and Conciliation Chamber (CCAF), thereby extinguishing the ADI.

Stock bonus: In December 2025, the Company approved the capitalization of R$ 30 billion from profit reserves through the issuance of Class C preferred shares (PNC) as a stock bonus. Additionally, the Company created immediately and compulsorily redeemable preferred shares (PNR) for holders of Class A and B preferred shares to enable payment of the premium to which preferred shareholders are entitled.

Portfolio management: Management delivered significant and consistent milestones in October, accelerating the Company's streamlining and de-risking efforts. Key transactions include:

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Completion of the sale of the Santa Cruz TPP, the last thermal asset. With this transaction, AXIA Energia now holds a 100% renewable portfolio, aligned with its Net Zero 2030 commitment

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Execution of the sale agreement for Eletronuclear

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Execution of the acquisition agreement for Tijoá Energia

In addition, we completed the sale of EMAE stake in January 2026.

Investments: R$ 3,869 million in 4Q25, up by 43% and 28% compared to 3Q25 and 4Q24, respectively. It is worth noting the 57% YoY increase in transmission segment investments in reinforcements and improvements, which reached R$ 1,992 million in the quarter and the annual record of R$ 4,757 million in 2025.

Still within the transmission segment, 224 large-scale projects are under implementation, representing an additional RAP of R$ 1.8 billion between 2025 and 2030 with a total estimated CAPEX of R$ 14.0 billion.

Financial management: net debt totaled R$ 46,484 million in 4Q25, up by R$ 3,908 million and R$ 8,814 million compared to 3Q25 and 4Q24, respectively. This increase was due to the higher gross debt and lower available cash, resulting from the R$ 4.3 billion dividend payment in December 2025, which consumed a portion of the R$ 4.1 billion in free cash generated during the period. The average debt maturity decreased by 3.6 months while the average cost rose to CDI + 0.63% p.a. in 4Q25 from CDI + 0.07% p.a. in 4Q24, reflecting a 275 bps increase in the benchmark interest rate (Selic).

Capital raising transactions worth highlighting:

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Axia Norte raised R$ 2 billion and Axia Energia raised R$ 1 billion through debenture issuances in December 2025

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Axia Energia raised R$ 2 billion through debenture issuance in February 2026

Compulsory loan: the provision inventory was reduced by R$ 2.6 billion YoY and R$ 663 million sequentially, totaling R$ 11.1 billion in 4Q25. Agreements reached and favorable decisions led to a net reversal of R$ 138 million in the quarter.

4Q25 Financial Highlights

Adjusted regulatory net revenue: R$ 9,915 million in 4Q25, down 5.5% YoY, reflecting lower generation revenue due to the sale of thermal power plants and the R$ 250 million negative impact from wind farm reimbursements, partially offset by the higher transmission revenue. On a sequential basis, the increase in generation revenue partially offset the decline in transmission revenue, which was explained by lower collection of items that will be compensated through PA in the following cycle, amounting to R$ 225 million.

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$ 101/MWh in 4Q25 from R$ 78/MWh in 4Q24, considering the resources available for allocation in both segments.

Contribution margin from transmission: R$ 3,924 million in 4Q25, up 3.1% vs. R$ 3,805 million in 4Q24, mainly reflecting the lower PA in the current tariff cycle. Sequentially, when compared to the R$ 4,187 million recorded in 3Q25, the R$ 263 million decrease in the contribution margin was mainly explained by the R$ 225 million mentioned above (additional information on page 25).

Adjusted PMSO:

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IFRS: R$ 1,763 million in 4Q25, down 14.4% compared to R$ 2,060 million in 4Q24.

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Regulatory: R$ 1,761 million in 4Q25, down 15.9% compared to R$ 2,093 million in 4Q24.

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Two key events in the quarter impacted both IFRS and regulatory frameworks:

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R$ 108 million related to changes applied to the Profit Sharing (PLR) and Long-Term Incentive programs (ILP) at the end of 4Q25 to reinforce the alignment between performance, value generation and the Company's strategic priorities

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R$ 60 million in rebranding expenses related to the AXIA Energia brand launch announced in October

Adjusted Provision:

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IFRS: R$ 129 million provision in 4Q25, compared to a R$ 406 million provision in 4Q24.

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Regulatory: R$ 147 million provision in 4Q25, compared to a R$ 150 million provision in 4Q24.

Adjusted Regulatory EBITDA: EBITDA reached R$ 5,745 million in 4Q25, up 12.9% YoY, delivering consistent evolution, driven by:

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A 5.8% increase in transmission revenues

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A 15.9% drop in PMSO expenses, reflecting the continuous pursuit of operational efficiency

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A 28.9% increase in equity income, even excluding Eletronuclear and EMAE

These advances more than offset the 12.4% decrease in generation revenue.

Table 1 - Adjusted Regulatory EBITDA

	4Q25	3Q25	4Q24
Generation, transmission and others	10,067	9,646	10,356
Non-adjusted revenue, generation: wind plant reimbursement	-250	0	0
Non-adjusted revenue, transmission: pass-through items, compensated through the Adjustment Portion (PA) in the following cycle	98	323	139
Net Revenue	9,915	9,969	10,495
Energy for resale, grid charges and fuel	-2,733	-2,732	-3,528
Personnel, Materials, Services and Others	-1,761	-1,538	-2,093
Costs and expenses	-1,593	-1,537	-2,093
Non-adjusted expense: improvements of the PLR and ILP programs	-108	0	0
Non-adjusted expense: rebranding	-60	-1	0
Results before Provisions and Equity Interests	5,421	5,699	4,874
Operating Provisions	-147	207	-150
Results before Equity Interests	5,274	5,906	4,724
Equity holdings	470	476	365
EBITDA	5,745	6,382	5,089

Chart 1 - Results before Provisions and Equity Interests: non-adjusted events

(1) Pass-through items that will be compensated through the Adjustment Portion (PA) in the following cycle.

(2) Rebranding expense was R$ 60 million in 4Q25 and R$ 1 million in 3Q25, summing up to R$ 61 million in 2025.

Income and Social Contribution Taxes on Net Income, IFRS: The highlight in 4Q25 was the recognition of R$ 12,362 million in deferred tax assets, explained by changes in estimates of future taxable income. It is worth noting that the amount of R$ 2,493 million, relating to non-operating results, remains unrecognized.

Adjusted IFRS Net Income: Reached R$ 1,251 million, up 141% YoY, driven by lower PMSO expenses, reduced provisions, and decreased income tax and social contribution expenses, which more than offset the decline in generation contribution following thermal plant divestments.

MAIN OPERATIONAL AND FINANCIAL INDICATORS

Table 2 - Operating highlights

	4Q25	4Q24	∆%	3Q25	∆%	12M25	12M24	∆%
Generation and Trading
Installed Generation Capacity (MW)	43,872	44,246	-0.8	44,368	-1.1	43,872.3	44,245.7	-0.8
Assured Capacity (aMW) (1)	21,376	21,915	-2.5	21,655	-1.3	21,376.2	21,914.8	-2.5
Net Generation (TWh)	29.2	30.3	-3.8	24.5	19.0	137.9	143.6	-4.0
Energy Sold ACR (TWh) (2)	7.8	9.0	-12.8	8.0	-1.6	34.6	40.3	-14.3
Energy Sold ACL (TWh) (3)	18.1	18.0	0.7	16.4	10.2	70.6	63.3	11.5
Energy Sold Quotas (TWh) (4)	5.4	8.6	-37.0	5.0	7.9	20.8	34.5	-39.7
Average ACR Price (R$/MWh) (5)	217.25	236.21	-8.0	220.75	-1.6	217.8	227.9	-4.4
Average ACL Price (R$/MWh)	174.78	165.25	5.8	164.89	6.0	160.8	158.7	1.3
Transmission
Transmission lines (km)	74,769	74,013	1.0	74,769	0.0	74,769.4	74,013.1	1.0
RAP (R$ mm) (6)	16,733	17,095	-2.1	16,644	0.5	67,750	69,668	-2.8

(1) Assured Capacity (AC) reflects: (a) Ordinance GM/MME 544/21, which defined the revision of AC values of the plants that had their concession renewed due to capitalization (plants under the Quotas regime, Tucuruí, Itumbiara, Sobradinho, Mascarenhas de Moraes and Curuá-Una), with a significant reduction in AC as from 2023; (b) Ordinance GM/MME 709/22, with an Ordinary Review of the AC of hydroelectric plants as from 2023, affecting several AXIA Energia plants; (c) exit of Candiota III TPP as of Jan/24 and of Mauá III, Aparecida, Anamã, Anori, Codajás e Caapiranga TPPs as of May/25; (d) inclusion of HPP Colíder and exit of HPP Mauá as of Jun/25, after closing the uncrossing of interests/assets agreed with Copel; (e) inclusion of SPEs that started being consolidated: HPPs Teles Pires (Sep/23), Baguari (Oct/23), Retiro Baixo (Nov/23) and Santo Antonio (Nov/23); (f) it does not yet reflect the closing of the sale of the Santa Cruz TPP, concluded in Oct/25, or the consolidation of the Três Irmãos HPP, a transaction signed in Oct/25 that is still pending closing.

(2) Does not include quotas.

(3) Includes contracts under Law 13,182/2015.

(4) The figures shown are the Assured Capacity of quotas in GWh.

(5) Excludes thermal plants and reimbursement of ACR-d and CER contracts.

(6) Approved RAP for the current regulatory cycle, associated with active modules at the end of each period, including those that were active at the beginning of the cycle plus those that went into commercial operation. Includes transmission contracts of the companies AXIA Energia Holding, AXIA Energia Nordeste, AXIA Energia Sul, AXIA Energia Norte, TMT and VSB.

Table 3 - Financial highlights

	4Q25	4Q24	∆%	3Q25	∆%	12M25	12M24	∆%
Financial Indicators
Gross Revenue (R$ mn)	12,376	13,914	-11.1	11,725	5.6	48,405	47,725	1.4
Adjusted Gross Revenue (R$ mn)	12,376	13,914	-11.1	11,751	5.3	48,540	47,725	1.7
Net Operating Revenue (R$ mn)	10,666	12,025	-11.3	10,003	6.6	41,282	40,182	2.7
Adjusted Net Operating Revenue (R$ mn)	10,666	12,025	-11.3	10,029	6.4	41,417	40,182	3.1
Regulatory Net Operating Revenue (R$ mn)	9,915	10,495	-5.5	9,969	-0.5	39,158	40,145	-2.5
EBITDA (R$ mn)	4,442	5,027	-11.6	-1,495	-397.1	8,524	26,237	-67.5
Adjusted EBITDA (R$ mn)	4,209	4,672	-9.9	5,890	-28.5	19,666	25,488	-22.8
Regulatory EBITDA (R$ mn)	6,373	5,444	17.1	-601	n.m.	17,077	24,235	-29.5
Adjusted Regulatory EBITDA (R$ mn)	5,745	5,089	12.9	6,382	-10.0	23,004	23,487	-2.1
EBITDA Margin (%)	41.6	41.8	-0.2pp	-14.9	56.6pp	20.6	65.3	-44.6pp
Adjusted EBITDA Margin (%)	39.5	38.9	0.6pp	58.7	-19.3pp	47.5	63.4	-15.9pp
Net Income (R$ mn)	13,686	1,112	n.m.	-5,448	-351.2	6,560	10,381	-36.8
Adjusted Net Income (R$ mn)	1,251	518	141.4	2,123	-41.1	4,764	8,796	-45.8
Adjusted Gross Debt (R$ mn)	75,024	74,646	0.5	72,005	4.2	75,024	74,646	0.5
Adjusted Net Debt (Adj Net Debt) (R$ mn)	46,484	37,671	23.4	42,577	9.2	46,484	37,671	23.4
Adj Net Debt/Adjusted LTM EBITDA	2.4	1.5	59.9	2.1	11.8	2.4	1.5	59.9
Investments (R$ mn)	3,869	3,025	27.9	2,701	43.2	9,608	8,157	17.8

HIGHLIGHTS OF CONSOLIDATED RESULTS

1. CONSOLIDATED RESULT | IFRS AND REGULATORY

Table 4 - Income statement IFRS (R$ mm)

	4Q25			4Q24		3Q25		12M25	12M24
	IFRS	Adjustment	Adjusted	Adjusted	% Y/Y	Adjusted	% Q/Q	Adjusted	Adjusted	% Y/Y
Generation	7,021	0	7,021	7,986	-12.1	6,934	1.3	27,883	28,096	-0.8
Transmission	5,206	0	5,206	5,773	-9.8	4,646	12.1	20,116	19,293	4.3
Others	149	0	149	155	-3.6	171	-12.7	541	337	60.6
Gross Revenue	12,376	0	12,376	13,914	-11.1	11,751	5.3	48,540	47,725	1.7
(-) Deductions from Revenue	-1,710	0	-1,710	-1,889	-9.5	-1,723	-0.7	-7,123	-7,544	-5.6
Net Revenue	10,666	0	10,666	12,025	-11.3	10,029	6.4	41,417	40,182	3.1
Energy resale, grid, fuel and construction (1)	-4,912	0	-4,912	-5,366	-8.5	-4,147	18.5	-16,440	-15,226	8.0
Personnel, Material, Services and Others	-1,691	-73	-1,763	-2,060	-14.4	-1,542	14.4	-6,223	-6,860	-9.3
Operating provisions	-140	11	-129	-406	-68.3	-18	n.m.	-410	-1,241	-67.0
Results from asset sale	-53	53	0	0	0.0	0	0.0	0	0	0
Regulatory remeasurements - Transmission contracts	0	0	0	0	0.0	303	n.m.	-648	6,130	n.m.
Other income and expenses	225	-225	0	0	0.0	0	0.0	0	0	0.0
Results, before Equity holdings	4,095	-233	3,861	4,194	-7.9	4,625	-16.5	17,695	22,985	-23.0
Equity holdings	347	0	347	478	-27.4	1,265	-72.5	1,970	2,503	-21.3
EBITDA	4,442	-233	4,209	4,672	-9.9	5,890	-28.5	19,666	25,488	-22.8
D&A	-1,178	0	-1,178	-1,033	14.0	-1,156	1.9	-4,577	-3,988	14.8
EBIT	3,265	-233	3,031	3,639	-16.7	4,734	-36.0	15,089	21,500	-29.8
Financial Result	-2,306	161	-2,146	-2,754	-22.1	-2,385	-10.0	-10,227	-10,510	-2.7
EBT	958	-73	885	885	0.0	2,349	-62.3	4,862	10,990	-55.8
Income Tax and Social Contribution	12,728	-12,362	366	-367	n.m.	-226	n.m.	-98	-2,195	-95.5
Net Income	13,686	-12,435	1,251	518	141.4	2,123	-41.1	4,764	8,796	-45.8

(1) Energy purchased for resale includes: (a) short-term purchases (contracts with a duration of less than 12 months), (b) structural purchases (contracts with a duration of at least 12 months), and (c) results from agents (portions of power plants) that recorded negative settlement at the CCEE during the period. In addition, the effect of intercompany purchases is disregarded, as they are eliminated in accounting consolidation.

Table 5 - Regulatory IS (R$ mm)

	4Q25			4Q24		3Q25		12M25	12M24
	Regulatory	Adjustment	Adjusted	Adjusted	% Y/Y	Adjusted	% Q/Q	Adjusted	Adjusted	% Y/Y
Generation	7,021	0	7,021	8,018	-12.4	6,775	3.6	27,765	28,694	-3.2
Transmission (1)	4,455	0	4,455	4,210	5.8	4,745	-6.1	18,110	18,660	-2.9
Others	149	0	149	156	-4.2	171	-12.7	541	335	61.4
Gross Revenue	11,625	0	11,625	12,384	-6.1	11,691	-0.6	46,416	47,689	-2.7
(-) Deductions from Revenue	-1,710	0	-1,710	-1,889	-9.5	-1,723	-0.7	-7,123	-7,544	-5.6
Net Revenue	9,915	0	9,915	10,495	-5.5	9,969	-0.5	39,293	40,145	-2.1
Energy resale, grid, fuel and construction (2)	-2,733	0	-2,733	-3,528	-22.5	-2,732	0.0	-11,047	-11,051	0.0
Personnel, Material, Services and Others	-1,688	-73	-1,761	-2,093	-15.9	-1,538	14.5	-6,239	-6,933	-10.0
Operating provisions	237	-384	-147	-150	-1.9	207	n.m.	-116	-725	-84.1
Results from asset sale	-53	53	0	0	0.0	0	0.0	0	0	0
Regulatory remeasurements - Transmission contracts	0	0	0	0	0.0	0	0.0	0	0	0
Other income and expenses	225	-225	0	0	0.0	0	0.0	0	0	0.0
Results, before Equity holdings	5,903	-628	5,274	4,724	11.7	5,906	-10.7	21,891	21,436	2.1
Equity holdings	470	0	470	365	28.9	476	-1.3	1,113	2,051	-45.7
EBITDA	6,373	-628	5,745	5,089	12.9	6,382	-10.0	23,004	23,487	-2.1
D&A	-1,615	0	-1,615	-1,620	-0.3	-1,589	1.6	-6,410	-6,038	6.2
EBIT	4,758	-628	4,129	3,469	19.0	4,793	-13.8	16,594	17,448	-4.9
Financial Result	-2,233	455	-1,778	-3,034	-41.4	-2,475	-28.1	-9,926	-11,201	-11.4
EBT	2,525	-174	2,351	435	n.m.	2,318	1.4	6,668	6,247	6.7
Income Tax and Social Contribution	11,444	-11,196	248	663	-62.5	-462	n.m.	-559	-791	-29.3
Net Income	13,969	-11,369	2,599	1,098	136.7	1,856	40.0	6,110	5,456	12.0

(1) The figures in both lines relating to 4Q24 presented in this report show two differences compared to those originally disclosed on March 13, 2025. While gross transmission revenue decreased by R$ 209 million, from R$ 4,419 million to R$ 4,210 million, the cost of network usage charges, recorded under Energy Resale, Grid, Fuel and Construction, also decreased by R$ 209 million, from R$ 3,757 million to R$ 3,528 million. Therefore, the net effect on EBITDA and net income is nil. The change in both line items stems from a 2025 revision of accounting practices for eliminations of transactions between the Company's generation and transmission segments, given that the network usage charges paid by certain power plants in the generation segment have a corresponding revenue receipt by transmission companies within the group. To ensure comparability between 2024 and 2025, the 2024 elimination amounts were revised.

(2) Energy purchased for resale includes: (a) short-term purchases (contracts with a duration of less than 12 months), (b) structural purchases (contracts with a duration of at least 12 months), and (c) results from agents (portions of power plants) that recorded negative settlement at the CCEE during the period. In addition, the effect of intercompany purchases is disregarded, as they are eliminated in accounting consolidation.

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, available on the Company’s Investor Relations website, under Market Information > Historical Financial Information.

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

	4Q25 IFRS	Difference	4Q25 Regulatory	Non-recurring Adjustment	4Q25 Regulatory Adjusted	4Q24 Regulatory Adjusted	% Y/Y
Generation	7,021	0	7,021	0	7,021	8,018	-12.4
Transmission	5,206	-751	4,455	0	4,455	4,210	5.8
Others	149	0	149	0	149	156	-4.2
Gross Revenue	12,376	-751	11,625	0	11,625	12,384	-6.1
(-) Deductions from Revenue	-1,710	0	-1,710	0	-1,710	-1,889	-9.5
Net Revenue	10,666	-751	9,915	0	9,915	10,495	-5.5
Construction	-2,022	2,022	0	0	0	0	0.0
Energy resale	-1,791	0	-1,791	0	-1,791	-2,238	-20.0
Grid	-1,062	157	-905	0	-905	-759	19.1
Fuel	-37	0	-37	0	-37	-531	-92.9
Energy resale, grid, fuel and construction (1)	-4,912	2,179	-2,733	0	-2,733	-3,528	-22.5
Personnel	-910	23	-887	77	-810	-942	-14.0
Material	-57	0	-57	0	-57	-73	-21.4
Services	-760	0	-760	92	-668	-731	-8.6
Others	37	-21	16	-242	-226	-347	-35.0
Personnel, Material, Services and Others	-1,691	3	-1,688	-73	-1,761	-2,093	-15.9
Operating provisions	-140	377	237	-384	-147	-150	-1.9
Results from asset sale	-53	0	-53	53	0	0	0.0
Regulatory remeasurements - Transmission contracts	0	0	0	0	0	0	0.0
Other income and expenses	225	0	225	-225	0	0	0.0
Results, before Equity holdings	4,095	1,808	5,903	-628	5,274	4,724	11.7
Equity holdings	347	123	470	0	470	365	28.9
EBITDA	4,442	1,931	6,373	-628	5,745	5,089	12.9
D&A	-1,178	-437	-1,615	0	-1,615	-1,620	-0.3
EBIT	3,265	1,493	4,758	-628	4,129	3,469	19.0
Financial Result	-2,306	73	-2,233	455	-1,778	-3,034	-41.4
EBT	958	1,567	2,525	-174	2,351	435	n.m.
Income Tax and Social Contribution	12,728	-1,284	11,444	-11,196	248	663	-62.5
Net Income, continued	13,686	282	13,969	-11,369	2,599	1,098	n.m.

Non-recurring Adjustments

The following adjustments refer to events considered non-recurring:

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PMSO (Personnel): R$ 77 million, of which:

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(+) R$ 56 million was severance

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(+) R$ 21 million was VDPs

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PMSO (Services): R$ 92 million from legal consulting services related to contingency reduction.

▪

PMSO (Other): -R$ 242 million, comprised of:

◦

(-) R$ 221 million associated with the reversal of supplier-related provisions

◦

(-) R$ 45 million due to the receipt of an insurance claim

◦

(+) R$ 24 million in payment of fees in an agreement to settle a lawsuit

◦

(+) R$ 1 million related to commitments under the self-managed health plan, which was replaced by a plan managed by a specialized market operator in 3Q25

▪

Operating Provisions: -R$ 384 million, resulting from:

◦

(-) R$ 462 million in estimated losses on investments and impairment

◦

(-) R$ 200 million due to the reversal of provisions for onerous contracts, primarily explained by the reassessment of the contract with the Jirau HPP

◦

(+) R$ 192 million in adjustments related to the compulsory loan share conversion process

◦

(+) R$ 86 million in provisions for litigation

▪

Asset Disposal: R$ 53 million reflecting the costs of M&A processes carried out throughout 2025.

▪

Other Revenues and Expenses: -R$ 225 million fully adjusted as non-recurring, given the atypical nature of the items that make up this item.

▪

Financial Result: R$ 455 million linked to the monetary restatement of litigation, comprising R$ 161 million from compulsory loan.

▪

Income Tax and Social Contribution: -R$ 11,196 million, including:

◦

-R$ 11,398 million related to deferred tax asset recognition from revised estimates

◦

R$ 203 million related to deferred tax effects from provision reversals

Regulatory Result: Adjusted EBITDA

In 4Q25, adjusted regulatory EBITDA totaled R$ 5,745 million, up R$ 656 million YoY, reflecting:

▪

Increase in generation revenue along with reduction in energy purchase expenses, excluding the operating results of thermal power plants

▪

Reduction in PMSO costs and expenses

▪

Increase in transmission revenue

These effects more than exceeded:

▪

The R$ 263 million decline in results from thermal power plants, with the completion of their divestment

▪

The increase in connectivity costs

▪

The lower contribution from equity income

Equity income was R$ 470 million in 4Q25, up R$ 105 million YoY, primarily driven by the higher contribution from the Belo Monte stake. Worth noting that 4Q25 results do not include income from the stakes in Eletronuclear, as the company was classified as asset held for sale, and in Equatorial Maranhão.

It is worth noting that if one excludes the results from the thermal power plants sold in May and October 2025, EBITDA went up R$ 919 million, to R$ 5,724 million in 4Q25 from R$ 4,805 million in 4Q24.

Table 7 - Adjusted regulatory EBITDA, without thermal power plants (R$ mm)

	4Q25	Thermal Power Plants (TPP)	4Q25 Excluding TPP	4Q24	Thermal Power Plants (TPP)	4Q24 Excluding TPP
Generation	7,021	68	6,953	8,018	1,369	6,649
Transmission	4,455	0	4,455	4,210	0	4,210
Others	149	0	149	156	0	156
Gross Revenue	11,625	68	11,557	12,384	1,369	11,015
(-) Deductions from Revenue	-1,710	-7	-1,704	-1,889	-78	-1,811
Net Revenue	9,915	62	9,853	10,495	1,290	9,204
Energy resale, grid, fuel and construction (1)	-2,733	-39	-2,693	-3,528	-943	-2,585
Personnel, Material, Services and Others	-1,761	-2	-1,759	-2,093	-63	-2,030
Operating provisions	-147	0	-147	-150	0	-150
Results, before Equity holdings	5,274	21	5,254	4,724	284	4,440
Equity holdings	470	0	470	365	0	365
EBITDA	5,745	21	5,724	5,089	284	4,805

3. ENERGY TRADING

AXIA Energia companies sold 31.4 TWh of energy in 4Q25, down 11.8% compared to the 35.6 TWh traded in 4Q24.

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): Teles Pires and Baguari HPPs (as of Oct/23), and Retiro Baixo and Santo Antônio HPPs (as of Nov/23).

Table 8 - Energy balance 4Q25 (aMW)

	2025	2026		2027

Resources (A)	16,996	16,984		17,833
Own resources (1) (2) (3) (4) (5)	14,211	15,533		16,702
Hydraulic	13,940	15,251		16,420
Wind	270	282		282
Energy Purchase (6)	2,785	1,452		1,130
Limit =>		Lower	Higher	Lower	Higher
Sales (B)	14,959	9,847	12,847	7,398	10,398
ACR - Except quotas	3,483	3,597		3,148
ACL - Bilateral Contracts + STM implemented (range) (6)	11,476	6,250	9,250	4,250	7,250
Average prices Contracts signed
Limit =>		Lower	Higher	Lower	Higher
Average Price of Sales Contracts (ACR and ACL - R$/MWh) (7)	175	185	205	195	225
Balance (A - B)	2,037	7,137	4,137	10,434	7,434
Balance considering estimated hedge (8)	0	4,362	1,362	7,446	4,446
Uncontracted energy considering estimated hedge (8)	—%	26%	8%	42%	25%

Contracts signed until 12/31/2025.

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 AXIA Energia Norte (as of 4Q23), is also included.

The energy balance does not include Independent Power Producers (IPPs) contracts resulting from the Amazonas Distribuidora de-verticalization process, thermal plant availability contracts, or Assured Capacity Quotas, whether in terms of resources, requirements (sales), or average prices.

Own Resources include the decotization plants (new IPPs) and the New Grants—Sobradinho, Itumbiara, Tucuruí, Curuá-Una, and Mascarenhas de Moraes. For hydroelectric projects, an estimated GFIS2 was considered, that is, the Assured Capacity adjusted for Internal Loss Factors, Basic Network Loss Factors, and Availability Factors, as well as adjustments for portfolio-specific characteristics.

The revised Assured Capacity values, as outlined in Ordinance No. 709/GM/MME, of November 30, 2022, have been taken into account.

With the gradual phasing out of quota-based generation legacy contracts (decotization), plants currently operating under the quota regime are gradually granted new concessions under the IPP regime over a five-year period beginning in 2023. The Assured Capacity values were established in Ordinance GM/MME No. 544/21.

Considering the new concession grants from 2023 onward for the Sobradinho, Itumbiara, Tucuruí, Curuá-Una, and Mascarenhas de Moraes plants, whose Assured Capacity values were established in Ordinance GM/MME No. 544/21.

The balances include all energy purchased for resale: (a) short-term purchases (contracts with a duration of less than 12 months) and (b) structural purchases (contracts with a duration of at least 12 months). Additionally, the balances include intercompany transactions, impacting both energy purchase and sales lines in the ACL, in the following amounts: approximately 900 aMW in 2025 and 550 aMW in 2026 and 500 aMW in 2027.

Average prices consider taxes in effect as of the date of this report (February 26, 2026).

The figures represent an estimate of uncontracted energy. The estimated values for 2025, 2026 and 2027 is 81.8%. Worth noting that the average historical GSF from 2019 to 2024 was 82.7%. Source: CCEE, obtained from the CCEE website at the following link: https://www.ccee.org.br/dados-e-analises/dados-geracao (in Portuguese only, select the MRE option in the panel). It is important to note that this is only an estimate, based on past events.

Table 9 - Assured capacity quotas of hydroelectric power plants (aMW)

	2025	2026	2027
Assured Capacity Quotas (9) (10)	2,626	1,313	0

This excludes the Assured Capacity of Jaguari HPP (12.7 aMW), whose concession remains under AXIA Energia's interim management.

10.

Decotization occurs gradually over a five-year period beginning in 2023. The Assured Capacity values applied from 2023 onward are those established in Ordinance GM/MME No. 544/21.

4. INVESTMENTS AND EXPANSION PROJECTS

Investments totaled R$ 3,869 million in 4Q25, with allocation as follows:

▪

R$ 2,441 million to transmission

▪

R$ 611 million to generation

▪

R$ 412 million to infrastructure

▪

R$ 195 million to Itaipu's HVDC project

▪

R$ 127 million to the environmental area

▪

R$ 83 million via investment in Transnorte Energia (TNE)

Among transmission-related investments, reinforcements and improvements stand out, with 54% concentrated on large-scale projects and 27% on small-scale projects.

The amount invested in infrastructure was allocated as follows:

▪

58% for IT

▪

25% for equipment and machinery

▪

17% for real estate

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 10 - Investments (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Generation Corporate	611	827	-26.1	289	n.m.	1,424	2,595	-45.1
Implementation / Expansion	57	283	-80.1	27	n.m.	165	1,210	-86.3
Maintenance	554	543	2.0	263	n.m.	1,259	1,385	-9.1
Transmission Corporate	2,441	1,442	69.3	1,203	n.m.	5,498	3,706	48.3
Expansion	422	136	n.m.	135	n.m.	696	255	n.m.
Reinforcements and improvements	1,992	1,266	57.4	1,061	87.9	4,757	3,304	44.0
Maintenance	26	40	-35.1	8	n.m.	44	147	-69.8
Infrastructure	412	381	8.3	181	n.m.	754	554	36.2
Environmental	127	126	0.8	69	82.8	311	368	-15.6
SPEs	83	0	0.0	282	-70.5	590	486	21.3
Generation - Contributions	0	0	0.0	0	0.0	0	478	n.m.
Generation - Acquisition	0	0	0.0	0	0.0	0	0	0.0
Transmission - Contributions	83	0	0.0	282	-70.5	590	8	n.m.
Transmission - Acquisition	0	0	0.0	0	0.0	0	0	0.0
Investment for Special Obligation – Itaipu HVDC	195	250	-21.8	677	-71.2	1,031	448	n.m.
Total	3,869	3,025	27.9	2,701	43.2	9,608	8,157	17.8

Expansion Projects - Transmission

Large Scale Projects

▪

Projects: 224^[1], including the Itaipu HVDC System Revitalization project. Throughout 4Q25, the sample was reduced from 230 to 224 projects, due to 38 projects that were energized and the inclusion of 32 new authorizations issued by the regulator.

▪

Estimated investment: R$ 6.09 billion, excluding the Itaipu HVDC System Revitalization project, as AXIA Energia is responsible solely for its execution, and therefore does not benefit from associated revenue while being fully reimbursed for the amount disbursed.

▪

Auctions: Investments of R$ 7.87 billion, mainly driven by the following SPEs: Nova Era Janapu, which was part of the sample since 2Q24, while Nova Era Catarina, Nova Era Ceará, Nova Era Integração and Nova Era Teresina were added in 3Q24^[2]. The lot acquired in Auction 01/2022, awarded to AXIA Energia Norte, was concluded in August 2025 — 13 months ahead of schedule.

▪

Additional associated RAP: R$ 1.8 billion between 2025-2030.

Small Scale Projects

▪

Works: 8,009 small-scale events under implementation or to be implemented, of which 7,577 were improvements and 432 were reinforcements. Data from ONS Improvement and Reinforcement Plan Management System (SGPMR).

Table 11 - Portfolio of ongoing transmission projects

	4Q25	4Q24	%	3Q25	%
Large Scale: Reinforcement and Improvement
Estimated Portfolio Investment (R$ bi)	6.1	6.8	-10.5	6.2	-1.9
Additional RAP associated (R$ bi)	1.0	1.1	-10.6	1.0	-3.5
# of projects in the beginning of the period	225	241	-6.6	244	-7.8
(-) energized	-38	-20	90.0	-20	90.0
(+) new authorizations	28	17	64.7	1	n.m.
# of projects in the end of the period	215	236	-8.9	225	-4.4
Large Scale: Expansion (Auctions in implementation)
Estimated Portfolio Investment (R$ bi)	7.9	6.4	23.8	6.2	26.1
Additional RAP associated (R$ bi)	0.9	0.7	27.2	0.7	19.4
# of projects in the beginning of the period	5	6	-16.7	6	-16.7
(-) energized	0	0	0.0	-1	n.m.
(+) new authorizations	4	0	0.0	0	0.0
# of projects in the end of the period	9	6	50.0	5	80.0
Small Scale
# of projects in the end of the period	8,009	10,030	-20.1	8,575	-6.6
Improvement	7,577	9,446	-19.8	8,088	-6.3
Reinforcement	432	584	-26.0	487	-11.3

^[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 224 projects will add 2,306 km of transmission lines and 13,139 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$ 46,484 million in 4Q25, up R$ 3,908 million sequentially and R$ 8,814 million YoY.

As a result of a 275 bps increase in the Brazilian basic interest rate (Selic), the Company's total average cost increased to CDI + 0.63% p.a. in 4Q25 from CDI + 0.07% p.a. in 4Q24 while average debt maturity was reduced by 3.6 months in 4Q25 when compared to 4Q24.

Table 12 - Net debt (R$ mm)

	12/31/2025	09/30/2025	12/31/2024
(+) Gross Debt, including derivatives	75,024	72,005	74,646
(+) Gross Debt	74,296	70,836	75,621
(+) Derivatives (currency hedge) Net	729	1,169	-974
(-) Cash and Cash Equivalents + Current Securities	27,552	28,256	35,524
(-) Restricted Cash for Loans and Financing	797	987	813
(-) Loans receivable	191	187	639
Net Debt	46,484	42,577	37,671
Adjusted Net Debt / Adjusted Regulatory EBITDA LTM	2.0x	1.9x	1.6x
Net Debt's Average Term (months)	54.5	55.5	58.1

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 2 - Debt maturity schedule after hedge (R$ billion)

Table 13 - Debt breakdown, including hedge

Index	Average Cost	Total Balance (R$ million)	Share of Total (%)
CDI +	CDI + 1.04%	41,233	55.0
IPCA	IPCA + 5.94%	24,587	32.8
% of CDI	122% of CDI	4,920	6.6
TJLP	TJLP + 2.07%	2,521	3.4
Fixed Rate	5.75% per year	1,565	2.1
EUR	2.64% per year	197	0.3
Total		75,024	100.0

6. COMPULSORY LOAN

AXIA Energia has implemented measures to mitigate risks associated with legal proceedings related to compulsory loans on electricity^[3]. 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:

▪

The inventory of provisions was reduced by R$ 2.6 billion YoY and R$ 663 million sequentially, totaling R$ 11.1 billion in 4Q25, mainly due to the agreements

▪

Net reversal of R$ 138 million due to executed agreements and favorable decisions in the quarter

▪

R$ 161 million was the amount recorded in 4Q25 under financial expenses related to monetary restatements

▪

With the execution of new agreements in 4Q25, R$ 78 million in guarantees previously deposited in court will be released upon approval, bringing the total released since 3Q22 to R$ 2.7 billion

Since 3Q22, when negotiations began, the provision inventory related to compulsory loan fell by R$ 14.8 billion, reaching R$ 11.1 billion in 4Q25, even considering the accumulated R$ 3.0 billion monetary restatement in the period. The agreements also enabled the elimination of R$ 10.9 billion in legal risks considered "off balance", of which R$ 1.1 billion was classified as possible and R$ 9.7 billion as remote.

Chart 3 - Total inventory of compulsory loan provisions 4Q25 x 4Q24 (R$ bn)

Chart 4 - Total inventory of compulsory loan provisions 4Q25 x 3Q25 (R$ bn)

^[3] 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 4Q25 the R$ 4 billion dividend payment in August 2025.

Table 14 - Cash flow (R$ mm)

	4Q25	4Q24	∆%
Adjusted Regulatory Result, before Equity Holdings	5,274	4,724	11.7
EBITDA Adjustment *	682	276	n.m.
Income Tax and Social Contribution	-381	-145	n.m.
Working Capital	-169	801	n.m.
Privatization Charges	0	0	n.m.
Dividends Received	672	447	50.3
Operating Cash Flow	6,079	6,104	-0.4
Investments **	-1,983	-2,000	-0.8
Free Cash Flow	4,095	4,103	-0.2
Debt Service	-1,297	-1,581	-18.0
Litigation	-2,153	-1,231	74.9
Guarantees and Restricted Deposits	-21	379	n.m.
Supplementary social security	-125	-117	6.6
Net Funding ***	2,645	5,655	-53.2
Receipt of Loans and Financial Charges	2	5	-67.0
Disposal of equity holdings	723	0	n.m.
Dividends	-4,204	-178	n.m.
Free Net Cash	-335	7,035	n.m.
Change in Restricted Cash (short and long term)	-309	17	n.m.
Change in Financial Investments (long-term)	-166	-7	n.m.
Net Cash	-811	7,044	n.m.

*Does not consider the adjustment to the asset disposal result 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, equity income, financial results, and taxes are analyzed on a consolidated basis.

Table 15 - Income statement 4Q25 (R$ mm)

Income Statement	IFRS (a)	Adjustment (b)	Regulatory (c)=(a)+(b)	Non Recurring (d)	Adjusted Regulatory (e)=(c)+(d)	Generation (e.1)	Transmission (e.2)	Others (e.3)	Eliminations (e.4) (1)
Gross Revenue	12,376	-751	11,625	0	11,625	7,021	4,719	149	-264
(-) Deductions	-1,710	0	-1,710	0	-1,710	-900	-795	-16	0
Net Revenue	10,666	-751	9,915	0	9,915	6,121	3,924	133	-264
Energy purchased for resale (2)	-1,791	0	-1,791	0	-1,791	-1,791	0	0	0
Charges on use of the electricity grid	-1,062	157	-905	0	-905	-1,169	0	0	264
Fuel for electricity production (net of CCC)	-37	0	-37	0	-37	-37	0	0	0
Other Generation Costs (3)	-65	0	-65	0	-65	-65	0	0	0
Construction costs	-2,022	2,022	0	0	0	0	0	0	0
Regulatory remeasurements	0	0	0	0	0	0	0	0	0
Contribution Margin	5,688	1,428	7,117	0	7,117	3,059	3,924	133	0
PMSO, excluded Other Generation Costs (3)	-1,626	3	-1,623	-73	-1,696
Provisions	-140	377	237	-384	-147
Results from asset sale	-53	0	-53	53	0
Other income and expenses	225	0	225	-225	0
Results, before Equity holdings	4,095	1,808	5,903	-628	5,274
Equity holdings	347	123	470	0	470
EBITDA	4,442	1,931	6,373	-628	5,745
D&A	-1,178	-437	-1,615	0	-1,615
EBIT	3,265	1,493	4,758	-628	4,129
Financial Result	-2,306	73	-2,233	455	-1,778
EBT	958	1,567	2,525	-174	2,351
Income Tax and Social Contribution	12,728	-1,284	11,444	-11,196	248
Net Income	13,686	282	13,969	-11,369	2,599

(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 as RAP. For accounting consolidation purposes (Tables 5 and 6), these amounts are eliminated from both transmission revenue and generation usage charges. For management purposes, gross transmission revenue in 4Q25 is R$ 4,719 million, and including the accounting elimination of -R$ 264 million, this translates into accounting revenue of R$ 4,455 million. In the case of generation connection charges costs, for management purposes, the value in 4Q25 is R$ 1,169 million, and including the accounting elimination of R$ 264 million, this translates into an accounting cost of R$ 905 million.

(3) 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 4Q25, the adjusted regulatory PMSO under the accounting view totaled R$ 1,761 million, composed of R$ 52 million in RHR hedge costs and R$ 13 million in other generation operating costs, both allocated in the margin from generation, and R$ 1,696 million in other cost and expense components for personnel, materials, services and other. At the same time, in 4Q25, the adjusted IFRS PMSO from an accounting perspective totaled R$ 1,763 million, comprised of R$ 52 million in RHR hedge costs and R$ 13 million in other generation operating costs, both allocated to the margin from generation, and R$ 1,698 million in other cost and expense components related to personnel, materials, services, and other.

Table 16 - Income statement 4Q24 (R$ mm)

Income Statement	IFRS (a)	Adjustment (b)	Regulatory (c)=(a)+(b)	Non Recurring (d)	Adjusted Regulatory (e)=(c)+(d)	Generation (e.1)	Transmission (e.2)	Others (e.3)	Eliminations (e.4) (1)
Gross Revenue	13,914	-1,530	12,384	0	12,384	8,018	4,574	156	-364
(-) Deductions	-1,889	0	-1,889	0	-1,889	-1,114	-769	-6	0
Net Revenue	12,025	-1,530	10,495	0	10,495	6,904	3,805	150	-364
Energy purchased for resale (2)	-2,062	-176	-2,238	0	-2,238	-2,238	0	0	0
Charges on use of the electricity grid	-968	209	-759	0	-759	-1,123	0	0	364
Fuel for electricity production (net of CCC)	-531	0	-531	0	-531	-531	0	0	0
Other Generation Costs (3)	-50	0	-50	0	-50	-50	0	0	0
Construction costs	-1,804	1,804	0	0	0	0	0	0	0
Regulatory remeasurements	0	0	0	0	0	0	0	0	0
Contribution Margin	6,610	307	6,917	0	6,917	2,962	3,805	150	0
PMSO, excluded Other Generation Costs (3)	-2,302	-34	-2,336	292	-2,043
Provisions	67	256	323	-473	-150
Results from asset sale	79	0	79	-79	0
Other income and expenses	95	0	95	-95	0
Results, before Equity holdings	4,549	530	5,079	-355	4,724
Equity holdings	478	-114	365	0	365
EBITDA	5,027	416	5,444	-355	5,089
D&A	-1,033	-587	-1,620	0	-1,620
EBIT	3,995	-170	3,824	-355	3,469
Financial Result	-2,930	-280	-3,210	176	-3,034
EBT	1,064	-450	614	-179	435
Income Tax and Social Contribution	48	1,030	1,078	-415	663
Net Income	1,112	580	1,692	-594	1,098

(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 5 and 6), these amounts are eliminated from both transmission revenue and generation usage charges. For management purposes, gross transmission revenue in 4Q24 is R$ 4,574 million, and including the accounting elimination of -R$ 364 million, this translates into accounting revenue of R$ 4,210 million. In the case of generation connection charges costs, for management purposes, the value in 4Q24 is -R$ 1,123 million, and including the accounting elimination of R$ 364 million, this translates into an accounting cost of -R$ 759 million.

(3) 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 4Q24, the adjusted regulatory PMSO under the accounting view totaled R$ 2,093 million, composed of R$ 39 million in RHR hedge costs and R$ 10 million in other generation operating costs, both allocated in the margin from generation, and R$ 2,043 million in other cost and expense components for personnel, materials, services and others. At the same time, in 4Q24, the adjusted IFRS PMSO from an accounting perspective totaled R$ 2,060 million, comprised of R$ 39 million in RRH hedging costs and R$ 10 million in other generation operating costs, both allocated to the margin from generation, and R$ 2,010 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$ 7,021 million in 4Q25, in line with adjusted IFRS generation revenue. In both 4Q24 and 3Q25, 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:

▪

R$ 276 million^[4] provision recorded in 4Q25 related to reimbursement to counterparties of availability contracts in the regulated market (ACR) and reserve energy contracts for wind farm generation shortfalls considering both annual and quadrennial assessments for the period from 2021 to 2025

▪

95% revenue reduction from thermal plant energy sales, as 4Q25 reflected only Santa Cruz TPP revenue through October 9, 2025, when the sale closed

Table 17 - Generation revenue by contracting environment (R$ mm)

Revenue Generation	Volume (aMW) (a)			Price (R$/MWh) (b)			Regulatory Revenue (c) = (a) x (b)
Revenue Generation	4Q25	% Y/Y	% Q/Q	4Q25	% Y/Y	% Q/Q	4Q25	% Y/Y	% Q/Q
(+) Regulated Market	3,552	-12.8	-1.6	186	-43.1	-19.6	1,457	-50.4	-20.8
Existing	3,343	14.8	3.1	211	-10.0	-4.3	1,555	3.4	-1.3
Reimbursement from ACR-d and CER (1)	0	0.0	0.0	0	0.0	0.0	-276	0.0	0.0
M&As (2)	126	29.6	5.5	391	29.9	63.4	109	68.3	72.4
HPP Tucuruí Extension (3)	0	0.0	0.0	0	0.0	0.0	0	0.0	0.0
Thermal	83	-92.2	-66.3	372	-36.0	0.9	68	-95.0	-66.0
(+) Free Market	8,191	0.7	10.2	175	5.8	6.0	3,161	6.6	16.8
Existing	8,098	-0.4	10.3	173	4.8	5.2	3,098	4.4	16.1
M&As (2)	93	0.0	0.3	307	0.0	66.1	63	0.0	66.6
(+) O&M (Quotas)	2,459	-37.0	7.9	88	1.3	-7.0	476	-36.1	0.4
(+) ST Market (CCEE) (4)	2,918	2.7	-9.8	299	37.1	21.7	1,928	40.9	9.9
(=) Revenue with energy sold	17,120	-9.6	3.4	186	-3.1	0.2	7,021	-12.4	3.6
(+) Other (5)	—	—	—	—	—	—	0	n.m.	n.m.
(=) Total Revenue	—	—	—	—	—	—	7,021	-12.4	4.0
Recurring	—	—	—	—	—	—	7,021	-12.4	3.6
Non-recurring	—	—	—	—	—	—	0	0.0	n.m.

Revenue Generation	Regulatory Revenue (c)			Accounting Adjustment (d) (6)			Accounting Revenue (e) = (c) + (d)
Revenue Generation	4Q25	4Q24	3Q25	4Q25	4Q24	3Q25	4Q25	4Q24	4Q25x4Q24	3Q25	4Q25x3Q25
Regulated Market	1,457	2,938	1,840	0	-32	159	1,457	2,907	-49.9%	1,998	-27.1
Free Market	3,161	2,967	2,707	0	0	0	3,161	2,967	6.6%	2,707	16.8
O&M (Quotas)	476	745	474	0	0	0	476	745	-36.1%	474	0.4
Short-term market (4)	1,928	1,369	1,755	0	0	0	1,928	1,369	40.9%	1,755	9.9
Energy Sales	7,021	8,018	6,775	0	-32	159	7,021	7,986	-12.1%	6,934	1.3
Others (5)	0	0	-26	0	0	0	0	0	n.m.	-26	n.m.
Total Revenue	7,021	8,018	6,749	0	-32	159	7,021	7,986	-12.1%	6,908	1.6
Recurring	7,021	8,018	6,775	0	-32	159	7,021	7,986	-12.1%	6,934	1.3
Non-recurring	0	0	-26	0	0	0	0	0	0.0%	-26	n.m.

(1) Provision due to energy committed under ACR-d and CER contracts, but neither generated nor supplied.

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

(3) 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 the following periods—generated a sold volume of 1,872 MWm, recognized revenue of R$ 1,327 million, and an average price of R$ 321/MWh.

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

(5) Main effect: recognition of a negative amount of R$ 26 million in 3Q25, 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.

(6) The differences between IFRS and regulatory revenues in 3Q25, and 4Q24 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.

^[4] Amount related to impact on gross revenue. The impact on net revenue was R$ 250 million.

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 increased to R$ 3,059 million in 4Q25 from R$ 2,962 million in 4Q24, despite the sale of thermal power plants and the lower volume of available energy due to the GSF (Generation Scaling Factor), which fell to 67.4% in 4Q25 from 79.9% in 4Q24.

In unit terms, the margin by volume of available energy (energy resource) increased to R$ 92.05/MWh in 4Q25 from R$ 84.96/MWh in 4Q24.

It is worth noting that, when excluding the thermal power plant results (Table 19), the unit contribution margin rose to R$ 91.55/MWh in 4Q25 from R$ 80/MWh in 4Q24, while energy resources remained practically stable, up to 15,026 aMW from 14,903 aMW, even with a lower GSF, attributable to the 2025 portfolio allocation strategy and protection via hydrological risk renegotiation.

Table 18 - Generation - adjusted contribution margin, regulatory (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Gross Revenue	7,021	8,018	-12.4	6,775	3.6	27,765	28,694	-3.2
Taxes	-588	-822	-28.4	-616	-4.5	-2,655	-3,228	-17.8
Sector charges	-311	-292	6.6	-274	13.8	-1,279	-1,250	2.3
Net Revenue	6,121	6,904	-11.3	5,886	4.0	23,830	24,215	-1.6
Energy purchased for resale (1)	-1,791	-2,238	-20.0	-1,681	6.5	-6,615	-5,695	16.2
Charges on use of the electricity grid (2)	-1,169	-1,123	4.0	-1,132	3.2	-4,505	-4,381	2.8
Fuel for electricity production (net of CCC (3))	-37	-531	-92.9	-193	-80.6	-1,013	-1,992	-49.2
Other Generation Costs	-65	-50	31.6	-69	-5.9	-258	-239	7.8
GSF Insurance (4)	-52	-39	32.9	-57	-8.1	-190	-207	-8.1
Others (5)	-13	-10	26.8	-13	3.9	-67	-32	n.m.
Contribution Margin	3,059	2,962	3.3	2,809	8.9	11,440	11,909	-3.9
Resources (MWm) (6)	15,053	15,791	-4.7	14,062	7.0	15,931	16,979	-6.2
Unit Margin (R$/MWh)	92	85	8.3	90	1.7	82	80	2.7

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

(3) 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.

(4) RHR: Renegotiation of Hydrological Risk

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

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

Table 19 - Generation, ex thermal power plants - adjusted contribution margin, regulatory (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Gross Revenue	6,953	6,649	4.6	6,575	5.7	25,465	23,593	7.9
Taxes	-582	-744	-21.8	-594	-2.2	-2,509	-2,551	-1.6
Sector charges	-311	-292	6.6	-274	13.8	-1,279	-1,225	4.4
Net Revenue	6,060	5,614	8.0	5,707	6.2	21,676	19,816	9.4
Energy purchased for resale (1)	-1,791	-1,862	-3.8	-1,671	7.2	-6,140	-4,669	31.5
Charges on use of the electricity grid (2)	-1,166	-1,070	9.0	-1,125	3.6	-4,280	-4,228	1.2
Fuel for electricity production (net of CCC (3))	0	0	0.0	0	0.0	0	0	0.0
Other Generation Costs	-65	-50	31.6	-69	-5.9	-258	-239	7.8
GSF Insurance (4)	-52	-39	32.9	-57	-8.1	-190	-207	-8.1
Others (5)	-13	-10	26.8	-13	3.9	-67	-32	111.9
Contribution Margin	3,038	2,632	15.4	2,841	6.9	10,998	10,680	3.0
Resources (MWm) (6)	15,026	14,903	0.8	13,816	8.8	15,570	16,241	-4.1
Unit Margin (R$/MWh)	92	80	14.4	93	-1.7	81	75	7.7

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

(3) 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.

(4) RHR: Repactuação do Risco Hidrológico, or Renegotiation of the Hydrological Risk

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

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

Table 20 - Generation - ajusted contribution margin, regulatory - by contracting environment (R$ mm)

	4Q25					4Q24		3Q25
	Total (a)=(b)+(c) +(d)+(e)	Thermal (b)	Quota (c)	ACR (d)	ACL + MCP (e)	ACL + MCP	% Y/Y	ACL + MCP	% Q/Q
Gross Revenue	7,021	68	475	1,388	5,089	4,335	17.4	4,462	14.1
(-) Adjustment	0	0	0	0	0	0	0.0	0	0.0
Adjusted Gross Revenue	7,021	68	475	1,388	5,089	4,335	17.4	4,462	14.1
(-) Taxes	-588	-7	-40	-116	-426	-485	-12.2	-403	5.5
(-) Sector Charges	-311	0	-43	-73	-195	-160	22.0	-163	19.7
(-) Energy purchased for resale (1)	-1,791	0	0	0	-1,791	-1,862	-3.8	-1,671	7.2
(-) Charges on use of the electricity grid (2)	-1,169	-2	-206	-299	-662	-510	29.8	-630	5.0
(-) Fuel for electricity production (3)	-37	-37	0	0	0	0	0.0	0	0.0
(-) Other Generation Costs	-65	0	-1	-55	-10	-7	42.3	-9	12.1
GSF Insurance (4)	-52	0	0	-52	0	0	0.0	0	0.0
Others (5)	-13	0	-1	-3	-10	-7	42.3	-9	12.1
Contribution Margin (f)	3,059	22	186	845	2,006	1,312	52.9	1,586	26.5

	Own Resources (MWm)				13,953	14,722	-5.2	13,010	7.3
	(-) Quotas				-2,459	-3,655	-32.7	-2,279	7.9
	(-) ACR (includes thermal plants)				-3,593	-4,475	-19.7	-3,584	0.3
	(+) Structural Purchases				1,100	1,069	2.8	1,052	4.5
	Resources (MWm) (6)				9,001	7,661	17.5	8,199	9.8
	Resources (MWh thousand) (6) (g)				19,874	16,916	17.5	18,103	9.8

	R$/MWh (f)/(g)				101	78	30.1	88	15.3

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

(3) 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.

(4) RHR: Renegotiation of Hydrological Risk

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

(6) 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 (ACL) and settled in the Short Term Market (MCP) increased to R$ 101/MWh in 4Q25 from R$ 78/MWh in 4Q24, considering the resources available for allocation in both environments.

The increase in resources available for allocation in the ACL and MCP reflected, from the energy balance requirements side, the release of volumes resulting from the decotization and committed to fulfilling the sales contracts of thermal power plants. This effect more than offset the reduction in total resources for trading, explained by the sale of thermal power plants. From the hydroelectric side, the strategy of allocating own energy throughout 2025 helped to neutralize the reduction in GSF (Generation Scaling Factor) in 4Q25.

The contribution margin increased to R$ 2,006 million in 4Q25 from R$ 1,312 million in 4Q24. This increase was explained by energy trading strategy results, with revenue growth despite flat energy purchase spending, more than offsetting the R$ 152 million increase in connection charges (TUST) during the period.

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:

▪

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

▪

discounts for unavailability

▪

additional RAP related to new facilities that entered into operations after the approval

▪

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$ 3,924 million in 4Q25, up 3.1% YoY, mainly reflecting the lower PA in the current tariff cycle.

It is worth noting that the RAP variation was primarily explained by:

▪

the repositioning of RBSE's financial component

▪

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

▪

the addition of RAP from reinforcement and improvement projects authorized by the regulator

The variation in PA was primarily explained by the occurrence in 4Q24, without a corresponding impact in 4Q25, of a negative Postponement portion related to the 2023 RTP, according to ANEEL Resolution 3,344/2024, applicable only to the 2024/2025 tariff cycle.

Sequentially, when compared to the R$ 4,187 million recorded in 3Q25, the R$ 263 million decrease in the contribution margin was mainly explained by lower collection of items that will be compensated through PA in the following cycle, including:

▪

R$ 113 million related to deficit between ONS-calculated collection and approved RAP for the tariff cycle

▪

R$ 82 million associated with uncollected fines on connection contracts terminated but unpaid by generators in the quarter

▪

R$ 44 million related to the reduction in deficit between ONS-calculated collection and approved RAP for the tariff cycle for a connection dedicated to Itaipu's exclusive use

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

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
RAP (1)	4,134	4,246	-2.6	4,134	0.0	16,760	17,279	-3.0
PA (1)	-117	-382	-69.5	-117	0.0	-998	-906	10.1
Approved RAP and Adjustment Portion	4,018	3,864	4.0	4,018	0.0	15,763	16,373	-3.7
Taxes and Sector Charges (2)	602	545	10.5	685	-12.1	2,460	2,284	7.7
Unavailability Discount (3)	-63	-60	5.2	-51	24.2	-244	-244	0.2
RAP Addition: new facilities	35	12	n.m.	9	n.m.	115	68	68.0
Pass through (4)	98	139	-29.6	323	-69.7	898	777	15.6
Other mismatches (5)	29	74	-61.2	36	-20.8	205	417	-50.9
Gross Revenue (6)	4,719	4,574	3.2	5,020	-6.0	19,196	19,676	-2.4
Tributes	-438	-458	-4.4	-479	-8.6	-1,779	-1,831	-2.8
Sector Charges (7)	-357	-312	14.5	-355	0.6	-1,383	-1,230	12.4
Net Revenue	3,924	3,805	3.1	4,187	-6.3	16,035	16,615	-3.5

(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 approved RAP and ONS billing related to prepayment apportionment,

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 22 - Operating costs and expenses (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Energy purchased for resale (1)	1,791	2,062	-13.2	1,681	6.5	6,340	4,992	27.0
Charges on use of the electricity grid	1,062	968	9.7	1,010	5.1	4,023	3,955	1.7
Fuel for electricity production	37	531	-92.9	193	-80.6	1,013	1,992	-49.2
Construction	2,022	1,804	12.1	1,262	60.2	5,065	4,287	18.2
Personnel, Material, Services and Others	1,691	2,352	-28.1	1,656	2.1	6,684	7,668	-12.8
Depreciation and Amortization	1,178	1,033	14.0	1,156	1.9	4,577	3,988	14.8
Operating provisions	140	-67	n.m.	236	-40.5	636	-227	n.m.
Result from asset sale	53	-79	n.m.	7,071	-99.2	7,229	36	n.m.
Regulatory remeasurements	0	0	0.0	-303	n.m.	4,082	-6,130	n.m.
Costs and expenses	7,974	8,604	-7.3	13,961	-42.9	39,648	20,562	92.8
*Non-recurring events*
(-) Non-recurring PMSO events	73	-292	n.m.	-114	n.m.	-461	-809	-43.0
(-) Non-recurring provisions	-11	473	n.m.	-218	-94.8	-226	1,467	n.m.
(-) Result from asset sale	-53	79	n.m.	-7,071	-99.2	-7,229	-36	n.m.
(-) Regulatory remeasurements	0	0	0.0	0	0.0	-3,433	0	0.0
Adjusted Costs and Expenses	7,982	8,864	-9.9	6,559	21.7	28,298	21,184	33.6

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

▪

Personnel: adjusted balance of R$ 833 million in 4Q25, down R$ 82 million when compared to the R$ 915 million in 4Q24, with the main effects being:

◦

R$ 178 million increase in Profit Sharing (PLR) and Short-Term Incentive (ICP) program expenses;

◦

R$ 110 million decrease in expenses related to compensation and changes:

◦

R$ 142 million savings from the Voluntary Dismissal Plans (PDVs)

◦

R$ 32 million increase with new hires

◦

R$ 92 million drop reflecting the capitalization of personnel costs, as a result of the increased level of investments in the period

◦

R$ 32 million decrease associated with benefits

◦

R$15 million reduction due to the sale of thermal power plants

Non-recurring effects: R$ 77 million, being:

◦

R$ 35 million with severance costs

◦

R$ 21 million with VDPs

◦

R$ 21 million related to Severance Indemnity Fund (FGTS) fine linked to terminations

▪

Material: adjusted balance of R$ 57 million in 4Q25, down R$ 16 million when compared to the R$ 73 million recorded in 4Q24, as a result of lower operational maintenance costs driven in part by the sale of thermal power plants.

There were no non-recurring effects in the quarter.

▪

Services: adjusted balance of R$ 668 million in 4Q25, down R$ 63 million when compared to the R$ 731 million in 4Q24, driven by:

•

R$ 101 million in savings on consulting and legal services contracts

•

R$ 60 million in increased expenses related to the company's rebranding

•

R$ 30 million reduction due to lower year-end payment concentration in 2025

Non-recurring effects: R$ 92 million related to success fee paid to legal defense as part of the contingency reduction strategy.

▪

Other: adjusted balance of R$ 205 million in 4Q25, down R$ 136 million when compared to the R$ 341 million in 4Q24, notably:

•

R$ 103 million reduction from the reclassification in 2025 of prior convictions as provisions

•

R$ 47 million increase in rental expenses from property return costs

•

R$ 33 million decrease in materials and product expenses

•

R$ 32 million decrease in taxes and charges, reflecting the sale of thermal power plants

Non-recurring effects: net positive effect of R$ 242 million in the quarter, highlighting:

◦

R$ 221 million associated with the reversal of supplier-related provisions

◦

R$ 45 million associated with insurance proceeds received from claims recovery

◦

R$ 24 million for settlement fees paid to terminate legal proceedings

◦

R$ 1 million associated with commitments under the self-managed health plan, which was replaced by a plan managed by a specialized market operator in 3Q25

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 23 - Detailed IFRS PMSO (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Personnel	889	984	-9.6	800	11.2	3,444	3,754	-8.3
VDP	21	182	-88.4	32	-33.5	247	227	8.8
Material	57	73	-21	63.4	-10	214.2	220	-3
Services	760	773	-1.7	548	38.8	2,202	2,238	-1.6
Others	-37	341	n.m.	213	n.m.	577	1,230	-53.1
other generation costs	65	50	31.6	69	-5.9	258	239	7.8
other expenses	-102	291	n.m.	143	n.m.	320	991	-67.8
PMSO (a)	1,691	2,352	-28.1	1,656	2.1	6,684	7,668	-12.8
Personnel	-56	-69	-18.4	-50	12.4	-274	-69	n.m.
VDP	-21	-182	-88.4	-32	-33.5	-247	-227	8.8
Material	0	0	0.0	0	0.0	0	0	0.0
Services	-92	-42	n.m.	-15	n.m.	-164	-84.2	95
Others	242	0	0.0	-18	n.m.	224	-429	n.m.
other generation costs	0	0	0.0	0	0.0	0	0	0.0
other expenses	242	0	0.0	-18	n.m.	224	-429	n.m.
Non recurring (b)	73	-292	n.m.	-114	n.m.	-461	-809	-43.0
Personnel	833	915	-8.9	750	11.1	3,169	3,685	-14.0
VDP	0	0	0.0	0	0.0	0	0	0.0
Material	57	73	-21.4	63	-10.0	214	220	-2.6
Services	668	731	-8.6	533	25.4	2,038	2,153	-5.4
Others	205	341	-39.8	195	5.0	801	801	0.1
other generation costs	65	50	31.6	69	-5.9	258	239	7.8
other expenses	140	291	-52.0	126	10.9	544	562	-3.2
PMSO adjusted (c) = (a) + (b)	1,763	2,060	-14.4	1,542	14.4	6,223	6,860	-9.3
PMSO excluding TPP * (c.1)	1,762	1,997	-11.8	1,535	14.7	6,149	6,684	-8.0
expenses	1,696	1,947	-12.9	1,466	15.7	5,892	6,445	-8.6
costs: generation segment **	65	50	31.6	69	-5.9	258	239	7.8
Thermal Power Plants (c.2)	2	63	-97.5	6	-74.9	74	176	-58.0

* TPP: Thermal Power Plants. PMSO of thermal plants sold to Âmbar.

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

Regulatory Remeasurement and Asset Disposal Result

▪

Regulatory Remeasurement - Transmission Contracts: There were no recognitions in this line in 4Q25.

▪

Asset disposal result: R$ 53 million expense in 4Q25, primarily due to costs related to M&A transactions executed throughout 2025.

Operating Provisions

Table 24 - Operating provisions - IFRS (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Operating Provisions / Reversals
Provision/Reversal for Litigation	-380	-486	-21.8	-419	-9.3	-885	160	n.m.
Estimated losses on investments	133	217	-38.6	12	n.m.	179	199	-10.2
Measurement at fair value of assets held for sale	0	-137	n.m.	0	0.0	0	0	0.0
Provision for the Implementation of Lawsuits - Compulsory Loan	-192	-23	n.m.	-15	n.m.	-201	-70	n.m.
ECL - Loans and financing	0	-4	n.m.	176	n.m.	166	-15	n.m.
ECL - Consumers and resellers	-84	-157	-46.4	-35	n.m.	-217	-391	-44.5
ECL - Other credits	-9	-44	-80.2	175	n.m.	133	-169	n.m.
Onerous contracts	200	251	-20.2	29	n.m.	288	387	-25.5
Results of actuarial reports	-67	-106	-37.3	-95	-29.7	-346	-490	-29.4
Other *	257	556	-53.8	-63	n.m.	247	616	-59.9
Operating Provisions / Reversals	-140	67	n.m.	-236	-40.5	-636	227	n.m.
*Non-recurring items / Adjustments*	11	-473	n.m.	218	-94.8	226	-1,467	n.m.
Provision for Litigation	380	427	-11.1	419	-9.3	885	-219	n.m.
Measurement at fair value of assets held for sale	0	79	n.m.	0	0.0	0	-214	n.m.
Estimated losses on investments	-133	-217	-38.6	-12	n.m.	-179	-199	-10.2
Provision for the Implementation of Lawsuits - Compulsory Loan	192	23	n.m.	15	n.m.	201	70	n.m.
ECL - Loans and financing	0	4	n.m.	-176	n.m.	-166	15	n.m.
Onerous contracts	-200	-251	-20.2	-29	n.m.	-288	-387	-25.5
Impairment	-227	-540	-58.0	0	0.0	-227	-534	-57.5
Restitution RGR	0	0	0.0	0	0.0	0	0	0.0
Adjusted Provisions/Reversals	-129	-406	-68.3	-18	n.m.	-410	-1,241	-67.0

Positive values in the table above indicate reversal of provision.

* Primarily Includes impairment and RGR refunds.

▪

Provision for litigation: provision of R$ 380 million in 4Q25 compared to a provision of R$ 486 million in 4Q24. The R$ 106 million variation was explained by the recording of provisions in civil, tax, labor, regulatory, environmental, land, and other proceedings, partially offset by the reversal of provisions in compulsory loan proceedings.

◦

Compulsory Loan: Contributed a net reversal of R$ 138 million in 4Q25, compared to the net reversal of R$ 359 million in 4Q24, reflecting agreements signed and favorable decisions. It is worth noting that, unlike other provisions, the monetary restatement related to the compulsory loan provision was recognized under financial results.

◦

Other events, contributing to results as follows:

•

Changes in provision balances: provision of R$ 349 million in 4Q25 vs. R$ 634 million in 4Q24, a positive variation of R$ 285 million

•

Monetary update: R$ 168 million expense in 4Q25 compared to R$ 210 million in 4Q24

▪

Share conversion process – Compulsory Loan: R$ 192 million provision in 4Q25, compared to a R$ 23 million provision in 4Q24. This result reflects the mark-to-market effect on the average price of the Company’s class B preferred shares over the past 12 months, related to amounts recorded in the balance sheet and linked to those shares. In addition, there is an impact from the increased provision due to the dividends of the period.

▪

Fair value measurement of asset held for sale: no recognitions in 4Q25, after a R$ 137 million provision was recorded in 4Q24, primarily relating to the devaluation of the equity stake in the SPE Mata de Santa Genebra.

▪

Estimated losses on investments: reversal of R$ 133 million in 4Q25 vs. reversal of R$ 217 million in 4Q24, an R$ 84 million variation mainly explained by:

◦

R$ 153 million: reversal of impairment in Norte Energia in 4Q24

◦

R$ 122 million: reversal of equity holdings in SPEs MESA, Sinop and São Manoel

◦

R$ 88 million: reversal of impairment in AXIA Energia Nordeste in 4Q24

◦

R$ 68 million: provisions for equity holdings in ISA Energia Brasil in 4Q24

▪

Expected Credit Losses (ECL) - Consumers and Resellers: provision of R$ 84 million in 4Q25, due to:

◦

R$ 69 million related to uncollected Transmission System Usage Charges (EUST)

◦

R$ 41 million from monetary update

▪

Onerous Contracts: R$ 200 million reversal in 4Q25 compared to a R$ 251 million reversal in 4Q24. The recognition is predominantly explained by the reassessment of the contract with the Jirau HPP.

▪

Impairment: The R$ 227 million amount recognized in 4Q25 resulted from impairment testing of the Casa Nova (R$ 141 million), Coxilha Negra (-R$ 340 million), and Ibirapuitã (R$ 28 million) wind farms, as detailed in the table below:

Table 25 - Impairment test result (R$ mm)

	Balance on 12/31/2024	Changes	Balance on 12/31/2025
Hydro Division - AXIA Energia	0	0	0.0
Hydro Division - AXIA Energia Norte	0	0	0.0
Hydro Division - AXIA Energia Nordeste	0	0	0.0
Hydro Division - AXIA Energia Sul	0	0	0.0
Casa Nova	407	141	548.7
Casa Nova B to G	0	0	0.0
Coxilha Negra	476	-340	135.6
Ibirapuitã	31	-28	3.3
Others	262	-182	79.5
Total	1,176	-409	767.1

8.5. Equity Holdings - IFRS

The main highlights of equity income were as follows:

▪

Eletronuclear: No income was recognized in 4Q25 as the asset was classified as held-for-sale

▪

ISA Energia: reduction due to higher financial expenses from new debt raised for investment execution

▪

Equatorial Maranhão: variation resulting from the non-recognition of equity accounting in 4Q25

▪

Belo Monte Transmissora de Energia S.A.: reduction from contractual asset adjustment for lower IPCA in 4Q25 versus 4Q24

▪

Norte Energia: increase due to deferred tax asset write-offs in 4Q24 with no counterpart in 4Q25

Table 26 - Equity holdings (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Highlights Affiliates (a)	173	406	-57.3	395	-56.1	800	1,951	-59.0
Eletronuclear (1)	0	22	n.m.	0	0.0	-84	562	-114.9
ISA Energia	148	251	-41.2	191	-22.7	498	900	-44.7
Equatorial Maranhão	0	75	n.m.	149	n.m.	149	149	0.0
Other Affiliates	26	58	-55.2	55	-52.7	237	340	-30.3
Highlights SPEs (b) (2)	59	-59	-200.6	751	-92.2	709	146	387.3
IE Madeira	49	68	-28.3	55	-10.5	219	196	11.6
Belo Monte Transmissora de Energia S.A. - BMTE	54	135	-59.6	95	-42.8	232	292	-20.3
Transnorte Energia (TNE)	19	51	-63.4	649	-97.1	591	148	299.7
Chapecoense	54	65	-17.0	59	-8.9	211	194	9.0
ESBR Jirau	37	32	16.9	57	-34.6	156	87	79.2
IE Garanhuns	14	19	-24.1	15	-0.9	67	64	4.9
Norte Energia	-169	-429	-60.6	-179	-5.7	-767	-835	-8.1
Other Holdings (c) (3)	115	131	-11.8	119	-3.1	345	409	-15.7
Total Equity Holdings (a) + (b) + (c)	347	478	-27.3	1,265	-72.5	1,854	2,506	-26.0
Non-recurring events
(-) Regulatory remeasurements, ISA Energia	0	0	0.0	0	0.0	116	0	0.0
Adjusted Equity Holding	347	478	-27.3	1,265	-72.5	1,970	2,506	-21.4

(1) 4Q25 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 in the balance sheet value of affiliates measured at fair value/cost.

8.6. Financial Result - IFRS

Table 27 - Financial result (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Financial Income	1,173	971	20.8	1,272	-7.8	4,586	3,152	45.5
Interest income, fines, commissions and fees	0	22	n.m.	38	n.m.	61	139	-56.0
Income from financial investments	1,198	982	21.9	1,228	-2.5	4,585	2,938	56.1
Late payment surcharge on electricity	25	23	7.4	16	50.8	109	120	-8.5
Other financial income	23	46	-50.1	68	-66.2	144	224	-35.7
(-) Taxes on financial income	-72	-103	-29.6	-79	-7.8	-312	-268	16.7
Financial Expenses	-2,427	-2,589	-6.3	-2,269	7.0	-9,539	-10,140	-5.9
Debt Charges (1)	-1,403	-1,556	-9.8	-1,444	-2.8	-6,016	-6,117	-1.7
Loans, financing and suppliers	-1,399	-1,426	-1.9	-1,439	-2.8	-5,801	-5,589	3.8
Leasing	-4	-130	-96.6	-5	-8.7	-215	-529	-59.3
CDE obligation charges (2)	-682	-640	6.6	-665	2.5	-2,670	-2,484	7.5
River basin revitalization charges (2)	-82	-87	-5.9	-80	2.0	-319	-340	-6.1
Financial discount for early payment - ENBpar	0	0	0.0	0	0.0	0	0	0.0
Other financial expenses	-260	-306	-15.0	-79	n.m.	-534	-1,199	-55.4
Net Financial Items	-1,052	-1,312	-19.8	-1,575	-33.2	-5,974	-4,640	28.7
Monetary changes	-121	-242	-50.0	-196	-38.2	-865	-778	11.2
Compulsory Loan	-161	-176	-8.7	-186	-13.8	-700	-769	-9.0
Others	40	-66	n.m.	-9	n.m.	-166	-9	n.m.
Exchange rate variations	-7	-56	-87.4	6	n.m.	-8	-29	-70.8
Change in fair value of hedged debt net of derivative (1)	-685	-274	n.m.	-1,056	-35.1	-3,294	-1,566	n.m.
Monetary updates - CDE (2)	-207	-508	-59.4	-270	-23.5	-1,525	-1,605	-5.0
Monetary updates - river basins (2)	-33	-92	-64.2	-42	-21.5	-240	-288	-16.7
Change in derivative financial instrument not linked to debt protection	0	-140	n.m.	-17	n.m.	-41	-374	-89.1
Financial Results	-2,306	-2,930	-21.3	-2,571	-10.3	-10,927	-11,628	-6.0
*Adjustments*
Monetary restatement - Compulsory Loan	161	176	-8.7	186	-13.8	700	769	-9.0
Write-off of judicial deposits due to the conciliation project	0	0	0.0	0	0.0	0	100	n.m.
Adjustment of the correction rate for judicial deposits	0	0	0.0	0	0.0	0	249	n.m.
Adjusted Financial Result	-2,146	-2,754	-22.1	-2,385	-10.0	-10,227	-10,510	-2.7

(1) To properly assess interest expense on total debt, including hedge results contracted to protect part of the debt, the analysis must consider both line items: "debt charges" and "change in fair value of hedged debt, net of derivative." The first reflects interest on the unhedged portion of debt, while the second reflects not only interest on the hedged portion of debt but also fair value changes of the associated hedging instruments.

(2) 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:

▪

Financial Income: went up 21% YoY, to R$ 1,173 million in 4Q25 from R$ 971 million in 4Q24, primarily explained by the increase in the average CDI rate during the period, which exceeded the 13% reduction in average cash balance

▪

Interest expense on debt and change in fair value of hedge: resulting, respectively, from the expenses related to:

•

R$ 1,403 million from debt charges

•

R$ 685 million from the change in the fair value of hedged debt, net of derivatives

•

In 4Q25, these lines totaled R$ 2,088 million compared to R$ 1,830 million in 4Q24. This 14% increase stemmed primarily from higher Selic rate and new hedge contracts, partially offset by lower leasing charges after thermal plant sales

▪

Monetary variations: R$ 121 million expense in 4Q25, down 50% from R$ 242 million in 4Q24. This line is comprised by two main components:

◦

Lawsuit update for compulsory loans: R$ 161 million expense in 4Q25 from R$ 176 million in 4Q24, reflecting the reduction in the provision inventory, which offset the higher Selic rate

◦

Other lines: R$ 40 million income in 4Q25 compared to a R$ 66 million expense in 4Q24, mainly explained by a R$ 52 million decrease in debt monetary restatement resulting from lower inflation-adjusted debt balances during the period

▪

Other financial expenses: R$ 260 million in 4Q25, down 15% from the R$ 306 million in 4Q24. The reduction was mainly explained by the R$ 34 million judicial deposits write-off in 4Q24, with no corresponding entry in 4Q25.

8.7. Current and Deferred Taxes - IFRS

In 4Q25, the highlight was the recognition of R$ 12,362 million in deferred tax assets, comprising:

▪

R$ 3,512 million related to deferred tax on tax loss carryforwards and negative tax base

▪

R$ 9,053 million related to deferred tax on temporary differences

This event is explained by changes in estimates of future taxable profits. It is important to note that R$ 2,493 million related to non-operating results remains unrecognized.

Non-recurring effects: -R$ 12,362 million, including:

▪

-R$ 12,565 million related to the deferred tax assets recognized as described above

▪

R$ 203 million related to deferred tax on provision reversals

Table 28 - Income tax and social contribution (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Current income tax and social contribution	424	5	n.m.	-425	n.m.	-333	-718	-53.6
Deferred income tax and social contribution	12,304	43	n.m.	198	n.m.	13,873	478	n.m.
Income tax and social contribution total	12,728	48	n.m.	-226	n.m.	13,540	-240	n.m.
Adjustments
Constitution/Reversal of Deferred Tax on Tax Loss (1)	-12,565	-1,425	n.m.	0	0	-12,565	-2,207	n.m.
Deferred Tax Adjustment on Regulatory Remeasurement (2)	0	758	n.m.	0	0	-882	0	0.0
Deferred Tax Adjustment on AXIA Energia Norte's tax rate	0	0	0.00	0	0.00	-393	0	0.0
Deferred Tax on Provisions: onerous contracts and impairment	0	252	n.m.	0.0	0	0	252	n.m.
Deferred Tax Adjustment on Provision Reversal	203	0	0.00	0	0.00	203	0	0.0
Adjusted income tax and social contribution	366	-367	n.m.	-226	n.m.	-98	-2,195	-95.5

(1) The amount of R$ 12,565 million in 4Q25 refers to the recognition of deferred tax assets on tax loss carryforwards, negative basis and temporary differences, following the revision of future taxable income. In 4Q24, the net constitution of R$ 1,425 million reflects the constitution of R$ 1,594 million at AXIA Energia, after studies of the recoverability of negative tax bases and temporary differences, combined with the reversal of R$ 169 million at AXIA Energia Sul, following the analysis of the recoverability of deferred tax resulting from the sale of TPP Candiota. In 2Q24, two amounts were recognized: R$ 1,074 million at AXIA Energia, related to tax credits, stemming from accumulated tax loss carryforwards, following a reassessment of taxable income due to the merger with Furnas; and a reversal of R$ 292.4 million at AXIA Energia Sul, based on a revised expectation regarding the completion of the operations required to utilize the tax credit generated by the sale of TPP Candiota.

(2) In 2Q25, the amount of R$ 882 million was recognized in connection with the Regulatory Remeasurement, due to changes in the payment schedule of the RBSE financial component for contracts extended under Law 12,783/2013, for 2025-26, 2026-27 and 2027-28 cycle, as approved by ANEEL's Board at its 20th Ordinary Public Meeting on June 10, 2025. In 4Q24, the amount of R$ 758 million refers to the regulatory remeasurement of AXIA Energia's contractual assets carried out in 3Q24. Although the remeasurement was recognized in that period, the corresponding deferred tax expense was recorded in 4Q24. On that occasion, the expense was reallocated to 3Q24, in line with its recurring nature in fiscal year 2024, consistent with the treatment given to the taxable event and the expenses of the other subsidiaries recognized in 3Q24 .

9. OPERATIONAL PERFORMANCE

9.1. Generation Segment

Generation Assets

The Company had 81 plants, including 47 hydroelectric, 33 wind, and 1 solar at the end of 4Q25, considering corporate ventures, shared ownership and stakes via SPEs. Compared to 3Q25, the decrease of one assets was primarily due to the sale of Santa Cruz TPP.

Portfolio installed capacity reached 43,872 MW in 4Q25, with 100% generated from clean sources with low greenhouse gas emissions, representing 17% of Brazil's total installed capacity.

Table 29 - Generation assets

Source	Installed Capacity (MW)	Assured Capacity (aMW)	Accumulated Generated Energy (GWh)
Hydro (47 plants)	43,073	21,028	136,698
Thermal (0 plants)	0	0	2,196
Wind Power (33 plants)	799	348	1,909
Solar (1 plant)	0.93	0.13	1.03
Total (81 plants)	43,872	21,376	140,803

Total energy generated by AXIA Energia fell by 3.2% YoY in 4Q25.

Chart 5 - AXIA Energia - net energy generation (GWh)

System Data – Installed Capacity and Generation

Brazil's installed capacity was 259,839.02 MW in 4Q25.

Chart 6 - Brazil’s installed capacity - by source

Source: ANEEL's Generation Information System (SIGA)

Chart 7 - Generated energy SIN - national interconnected system (GWh)

Source: Operating Results 01/01 to 12/31/2025 from the National Operator of the Electric System (ONS)

System Data – Energy Market

Table 30 - PLD

		4Q25	4Q24	∆%	3Q25	∆%
Market	GSF (%)	67.45	79.91	-12.5 p.p.	64.92	2.5 p.p.
	PLD SE (R$/MWh)	264.61	217.59	21.6	252.43	4.8
	PLD S (R$/MWh)	264.55	217.58	21.6	252.98	4.6
	PLD NE (R$/MWh)	252.85	206.71	22.3	239.96	5.4
	PLD N (R$/MWh)	263.83	218.23	20.9	250.98	5.1

Chart 8 - GSF (%)

Month	2021	2022	2023	2024	2025
December	87%	85%	86%	86%	73%

Chart 9 - Historical average of affluent natural energy (ENA) - SIN (%)

During 4Q25's transition from dry to wet season, energy inflows remained at approximately 70% of the SIN's long-term average due to below-average rainfall.

Chart 10 - Energy stored in reservoirs (EAR) - SIN (%)

The Brazilian Interconnected System (SIN) ended 4Q25 with stored energy at 45%, showing sequential depletion from 3Q25.

9.2. Transmission Segment

The Company ended 4Q25 with 74.8 thousand km of transmission lines, compared to 74.0 thousand km in 4Q24. There were also 415 substations, being 299 owned and 116 operated by third parties.

Table 31 - Transmission lines (km)

Company	Own(1)	In Partnership (2)	Total
AXIA Energia Nordeste	22,191	1,832	24,023
AXIA Energia Norte	10,988	2,013	13,001
AXIA Energia Sul	12,182	5	12,187
AXIA Energia Holding	22,129	3,429	25,558
Total	67,491	7,279	74,769

(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 32 - ESG KPIs 4Q25

Pillar	KPI	4Q24	4Q25	Change
Planet	Accumulated GHG Emissions for the year (1)	4,456,065	1,843,909	-59%
Planet	(Scopes 1, 2 and 3) (tCO2e)	4,456,065	1,843,909	-59%
People	Accident Frequency Rate - own Employees (with time off)	0.75	0.43	-43%
	Women in the Workforce (%)	20%	21%	1 p.p.
	Leadership positions held by women (%) (2)	26%	25%	-1 p.p.
Governance	Complaints answered on time (%)	100%	100%	0 p.p.

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.

10. APPENDIX

10.1. Appendix 1 - Generation and Transmission Revenue IFRS

Generation revenue comprises:

▪

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)

▪

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

▪

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

▪

revenue from operation and maintenance, representing remuneration for energy sold under the quota regime

Table 33 - Generation operating revenue (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Power supply to non-end consumers	4,360	5,180	-15.8	4,235	3.0	18,311	18,812	-2.7
Power supply to end consumers	411	693	-40.8	422	-2.7	1,760	2,941	-40.2
CCEE	1,775	1,368	29.8	1,777	-0.1	5,699	3,278	73.8
O&M revenue	475	745	-36.2	474	0.2	1,978	3,064	-35.4
Generation Revenues	7,021	7,986	-12.1	6,908	1.6	27,748	28,096	-1.2
*Non-recurring items - Adjustments*	0	0	0.0	26	n.m.	135	0	0.0
Adjusted Generation Revenue	7,021	7,986	-12.1	6,934	1.3	27,883	28,096	-0.8

Transmission revenue comprises:

▪

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

▪

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

▪

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

Table 34 - Transmission operating revenue (R$ mm)

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Revenue from Operation & Maintenance (O&M)	1,829	1,863	-1.8	2,096	-12.8	8,006	7,725	3.6
Construction Revenue	1,810	1,811	-0.1	1,182	53.1	4,800	4,162	15.3
Contractual Revenue - Transmission	1,567	2,099	-25.3	1,367	14.6	7,309	7,405	-1.3
Transmission Revenues	5,206	5,773	-9.8	4,646	12.1	20,116	19,293	4.3
*Non-recurring items - Adjustments*	0	0	0.0	0	0.0	0	0	0.0
Adjusted Transmission Revenue	5,206	5,773	-9.8	4,646	12.1	20,116	19,293	4.3

10.2. Appendix 2 - PMSO Breakdown

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

	4Q25	4Q24	%	3Q25	%	12M25	12M24	%
Convictions, losses and legal costs	35	86	-59.0	60	-40.9	171	304	-43.8
GSF	19	20	-5.3	19	0.0	71	136	-47.9
Insurance	18	27	-33.2	24	-25.5	89	113	-20.8
Equity Holding	44	40	11.0	28	60.4	100	83	20.3
Donations and contributions	66	66	0.9	16	n.m.	133	147	-9.5
Rent	70	35	n.m.	23	n.m.	135	78	72.7
Recovery of expenses	-59	-3	n.m.	-61	-2.6	-145	-74	95.7
Taxes	24	29	-17.5	23	1.2	109	65	68.1
Others	-254	42	n.m.	81	n.m.	-86	378	n.m.
Total	-37	341	n.m.	213	n.m.	577	1,230	-53.1

The breakdown of PMSO by subsidiary for 4Q24 and 4Q25 will be made available following the publication of their financial statements.

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

Chart 11 - 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)

	PARENT COMPANY		CONSOLIDATED
	12/31/2025	12/31/2024	12/31/2025	12/31/2024

ASSETS
CURRENT
Cash and cash equivalents	4,660,994	16,387,945	16,417,860	26,572,522
Restricted cash	622,383	449,865	660,259	508,734
Securities	3,894,302	6,421,621	11,133,842	8,951,838
Clients	1,530,268	1,686,293	5,575,589	5,911,477
Transmission contract assets	4,765,705	4,634,940	10,693,181	10,539,570
Financing, loans and debentures	10,625	971,555	10,625	475,459
Remuneration for equity holdings	1,533,871	2,286,078	470,142	721,683
Taxes and Contributions	1,486,283	1,734,020	2,766,765	2,831,414
Income tax and social contribution	0	0	0	0
Right to compensation	723,294	865,299	752,496	893,254
Warehouse	53,048	50,576	422,546	441,471
Derivative financial instruments	0	500,998	64,334	692,660
Others	843,164	729,718	2,050,516	1,408,919
	20,123,937	36,718,908	51,018,155	59,949,001
Assets held for sale	1,011,461	1,353,723	1,072,431	4,502,102
	21,135,398	38,072,631	52,090,586	64,451,103
NON-CURRENT
LONG-TERM ASSETS
Restricted cash	1,605,632	1,430,650	3,436,804	3,170,749
Equity Holdings Income	425,002	181,049	0	0
Right to compensation	2,176	692,126	2,176	720,081
Financing, loans and debentures	180,568	1,894,322	180,568	163,140
Clients	132,067	171,017	522,859	602,411
Securities	440,401	421,933	722,673	433,341
Taxes and Contributions	2,582,258	2,356,369	3,178,769	2,715,445
Deferred income tax and social contribution	11,836,824	0	17,499,833	5,673,011
Bonds and deposits linked	4,216,310	3,693,298	5,762,270	5,190,344
Transmission contractual assets	18,746,924	21,223,812	53,567,662	56,848,086
Derivative financial instruments	516,782	1,269,677	1,072,386	1,544,095
Others	680,979	2,000,734	846,940	1,645,570
	41,365,923	35,334,987	86,792,940	78,706,273
INVESTMENTS
Equity Income	107,026,094	112,300,525	23,322,816	30,727,405
Held at fair value	1,175,539	839,546	1,175,539	861,234
Other Investments	1,200	19,387	18,830	97,987
	108,202,833	113,159,458	24,517,185	31,686,626
FIXED ASSETS	7,897,759	6,137,175	39,659,177	36,854,055

INTANGIBLE	20,477,493	20,779,526	76,625,705	78,173,273

TOTAL ASSETS	199,079,406	213,483,777	279,685,593	289,871,330

	PARENT COMPANY		CONSOLIDATED
LIABILITIES AND SHAREHOLDERS' EQUITY	12/31/2025	12/31/2024	12/31/2025	12/31/2024
CURRENT LIABILITIES
Loans, financing and debentures	7,172,085	8,329,966	13,204,167	12,809,872
Compulsory loans - Agreements	1,071,291	1,105,534	1,073,452	1,105,534
Compulsory loans	1,406,460	1,326,925	1,406,460	1,326,925
Suppliers	1,878,308	1,145,660	3,916,279	2,756,329
Taxes and Contributions	454,920	378,569	1,021,353	1,146,169
Income tax and social contribution	0	0	0	0
Onerous contracts	0	0	113,944	62,711
Shareholder remuneration	135,863	2,486,778	136,124	2,490,668
Personnel obligations	506,348	483,779	1,060,856	1,065,114
Reimbursement Obligations	0	0	300,694	55,517
Post-employment benefits	77	993	303,832	289,840
Provision for litigation	648,956	1,719,453	666,092	1,791,088
Sector charges	115,097	105,352	886,565	820,067
Obligations under Law 14,182/2021	1,044,757	814,819	3,738,498	2,916,199
RGR Returns	695,705	492,276	695,705	492,276
Leasing	36,483	8,429	72,981	26,861
Derivative financial instruments	1,100,992	824,125	1,651,632	1,175,652
Others	201,535	458,746	729,766	1,105,094
	16,468,877	19,681,404	30,978,400	31,435,916
Liabilities associated with assets held for sale	0	0	0	194,454
	16,468,877	19,681,404	30,978,400	31,630,370
NON-CURRENT
Loans, financing and debentures	36,918,552	40,926,187	61,091,597	62,810,702
Shareholder remuneration	0	0	0	0
Suppliers	0	0	11,646	7,959
Provision for litigation	14,086,402	15,658,437	19,242,041	21,583,395
Post-employment benefits	383,875	418,586	3,276,459	3,416,381
Obligations under Law 14,182/2021	11,393,664	11,111,765	40,028,165	39,105,924
RGR Returns	0	439,974	0	439,974
Onerous contracts	4,151	0	282,371	621,725
Reimbursement Obligations	0	0	56,766	15,286
Leasing	104,478	79,994	415,625	155,722
Concessions payable - Use of public assets	70,486	38,175	589,412	543,867
Advances for future capital increases	124,543	108,938	124,543	108,938
Derivative financial instruments	151,487	2,283	151,487	2,283
Sector charges	478,305	744,833	688,574	942,348
Taxes and Contributions	88,511	103,682	198,782	372,488
Deferred income tax and social contribution	0	1,566,835	2,421,481	4,287,021
Others	375,938	739,459	1,626,587	1,827,171
	64,180,392	71,939,148	130,205,536	136,241,184
SHAREHOLDERS' EQUITY
Share capital	100,135,201	70,099,826	100,135,201	70,099,826
Share issue costs	-108,186	-108,186	-108,186	-108,186
Capital Reserves and Granted Equity Instruments	14,689,872	13,910,768	14,689,872	13,910,768
Treasury shares	-3,034,806	-2,223,011	-3,034,806	-2,223,011
Profit reserves	11,818,426	43,905,041	11,818,426	43,905,041
Proposed additional dividend	0	1,535,196	0	1,535,196
Accumulated profit	0	0	0	0
Accumulated other comprehensive income	-5,070,370	-5,256,409	-5,070,370	-5,256,409
Amounts recognized in other comprehensive income classified as held for sale	0	0	0	0
Controlling shareholders	118,430,137	121,863,225	118,430,137	121,863,225
Non-controlling shareholders	0	0	71,520	136,551
TOTAL SHAREHOLDERS' EQUITY	118,430,137	121,863,225	118,501,657	121,999,776
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	199,079,406	213,483,777	279,685,593	289,871,330

Table 37 - Income statement (R$ thousand)

	PARENT COMPANY		CONSOLIDATED
	12/31/2025	12/31/2024	12/31/2025	12/31/2024
CONTINUING OPERATIONS
Net operating revenue	13,762,621	6,328,755	41,281,596	40,181,552
Operating costs	-9,367,759	-4,574,870	-23,564,406	-22,100,082
GROSS PROFIT	4,394,862	1,753,885	17,717,189	18,081,470
Operating expenses	-9,303,992	-1,820,525	-12,001,962	-4,591,744
Other income and expenses	346,274	128,351	459,000	126,201
Regulatory Remeasurements - Transmission Contracts	-1,762,645	2,229,490	-4,081,630	6,129,771
OPERATING RESULT BEFORE FINANCIAL RESULT	-6,325,501	2,291,201	2,092,597	19,745,698
FINANCIAL RESULT	-6,041,928	-4,386,422	-10,926,530	-11,628,120
Income from interest, fines, commissions and fees	247,839	832,164	60,991	138,666
Income from financial investments	2,086,955	1,438,836	4,584,506	2,937,517
Late payment surcharge on electricity	7,157	2,532	109,288	119,500
Other financial income	130,966	151,194	143,945	223,898
(–) Taxes on financial income	-159,470	-152,820	-312,379	-267,782
Financial Income	2,313,447	2,271,906	4,586,351	3,151,799
Debt charges	-3,705,756	-3,342,854	-6,015,871	-6,117,463
CDE obligation charges	-767,886	-362,827	-2,670,067	-2,484,198
River basin revitalization charges	-84,379	-45,170	-319,226	-339,854
Other financial expenses	-378,928	-903,474	-534,044	-1,198,578
Financial expenses	-4,936,949	-4,654,325	-9,539,208	-10,140,093
Monetary updates – CDE	-438,524	-213,976	-1,524,821	-1,604,680
Monetary updates – river basins	-62,643	-35,306	-240,111	-288,081
Monetary reliefs	-606,546	-662,794	-865,216	-778,157
Exchange rate variations	-17,019	28,022	-8,408	-28,821
Change in fair value of hedged debt net of derivative	-2,293,694	-1,119,949	-3,335,117	-1,566,482
Change in derivative financial instrument not linked to debt protection	0	0	0	-373,605
Financial items, net	-3,418,426	-2,004,003	-5,973,673	-4,639,826
PROFIT BEFORE EQUITY HOLDINGS	-12,367,429	-2,095,221	-8,833,933	8,117,578
Equity income	5,415,367	10,762,871	1,853,984	2,503,205
OPERATING PROFIT BEFORE TAX	-6,952,062	8,667,650	-6,979,949	10,620,783
Current income tax and social contribution	0	0	-333,039	-717,909
Deferred income tax and social contribution	13,510,537	1,710,472	13,872,646	477,879
NET INCOME FOR CONTINUING OPERATIONS	6,558,475	10,378,122	6,559,658	10,380,753
Portion attributable to controlling	6,558,475	10,378,122	6,558,475	10,378,122
Portion attributable to non-controlling	0	0	1,183	2,632
NET INCOME (LOSS) FOR DISCONTINUED OPERATIONS	0	0	0	0
Portion attributable to controlling	0	0	0	0
Portion attributable to non-controlling	0	0	0	0
NET INCOME FOR THE YEAR	6,558,475	10,378,122	6,559,658	10,380,753
Portion attributable to controlling	6,558,475	10,378,122	6,558,475	10,378,122
Portion attributable to non-controlling	0	0	1,183	2,631
EARNINGS PER SHARE
Earnings per share - basic (ON/PNC)	2.29	3.62	0.00	0.00
Earnings per share - basic (PNA/PNB)	2.52	3.98	0.00	0.00
Earnings per share - diluted (ON/PNC)	2.27	3.58	0.00	0.00
Earnings per share - diluted (PNA/PNB)	2.50	3.94	0.00	0.00

Table 38 - Cash flow statement (R$ thousand)

	PARENT COMPANY		CONSOLIDATED
	12/31/2025	12/31/2024	12/31/2025	12/31/2024
OPERATING ACTIVITIES
Profit for the year before income tax and social contribution	-6,952,062	8,667,650	-6,979,949	10,620,783
Adjustments to reconcile profit with cash generated by operations:
Depreciation and amortization	960,184	365,691	4,576,919	3,987,775
Net exchange and monetary variations	1,124,732	884,054	2,638,556	2,699,739
Result of acquisitions and divestments	7,303,947	0	7,229,469	0
Financial charges	4,008,003	1,479,851	7,712,001	5,865,332
Equity income	-5,415,367	-10,762,871	-1,913,039	-2,503,207
Other income and expenses	-346,274	-138,690	-459,000	-136,540
Transmission revenues	-7,469,600	-3,927,138	-20,115,786	-19,292,579
Construction cost - transmission	1,872,110	1,145,373	5,065,204	4,286,914
Regulatory Remeasurements - Transmission Contracts	1,762,645	-2,229,490	4,081,630	-6,129,771
Operating provisions (reversals)	-102,711	-15,097	635,737	-180,019
Write-offs of PP&E and Intangible Assets	7,959	95,193	-491,011	157,248
Result of hedged debt and derivatives	2,293,694	1,119,949	3,335,117	1,940,087
Other	369,893	1,356,943	469,521	1,557,887
	6,369,215	-10,626,232	12,765,318	-7,747,134
(Additions)/decreases in operating assets
Clients	57,498	-91,676	223,722	1,111,674
Right to compensation	892,154	715,010	918,862	752,350
Others	1,403,610	-656,660	455,268	673,834
	2,353,262	-33,326	1,597,852	2,537,858
Additions/(decreases) in operating liabilities
Suppliers	630,216	575,010	856,268	-614,240
Advances	0	0	0	0
Personnel obligations	-331,783	63,932	-358,610	-775,899
Sector charges	-278,311	651,238	-235,979	365,508
Others	107,313	423,719	-517,719	-605,675
	127,435	1,713,899	-256,040	-1,630,306
Payment of financial charges	-3,679,193	-4,113,742	-5,831,609	-6,650,869
Reversion global reserve Payment	-250,803	0	-250,803	0
Receipt of RAP revenue	7,606,911	3,531,148	18,714,804	19,248,186
Receipt of Financial Charges from Subsidiaries	179,995	784,913	0	0
Receipt of remuneration from investments in equity holdings	3,980,994	4,412,838	1,549,021	1,506,336
Payment of litigation	-3,609,370	-2,932,649	-5,272,014	-3,776,063
Bonds and linked deposits	-389,401	164,738	-410,453	195,871
Payment of income tax and social contribution	0	-73,214	-708,608	-1,488,382
Supplementary pension payments	-25,614	-49,120	-407,690	-430,698
Net cash provided by operating activities of discontinued operations	0	0	0	0
Net cash provided by (used in) operating activities	5,711,369	1,446,903	14,509,829	12,385,582
FINANCING ACTIVITIES
Loans and financing obtained and debentures obtained	1,000,000	17,246,220	8,032,447	29,965,839
Payment of loans and financing and debentures - principal	-7,149,789	-12,412,729	-11,312,024	-16,009,832
Payment of remuneration to shareholders	-12,186,149	-1,296,222	-12,186,149	-1,307,858
Payment to dissenting shareholders - incorporation of shares	0	0	0	0
Share buybacks	-36,728	-115,099	-36,728	-115,099
Payment of CDE obligations and revitalization of basins - principal	-725,773	0	-2,575,565	-1,974,965
Lease payments - principal	-30,113	-31,101	-50,980	-757,196
Derivatives Payment	-581,645	0	-962,193	0
Others	0	0	0	0
Net cash (used in) financing activities	-19,710,197	3,391,069	-19,091,192	9,800,889
INVESTMENT ACTIVITIES
Grant of advance for future capital increase	0	0	0	0
Receipt of loans and financing	1,811,564	5,128,284	447,231	12,675
Receipt of financial charges	209,698	57,665	209,698	57,665

	PARENT COMPANY		CONSOLIDATED
Acquisition of fixed assets	-648,463	-461,441	-2,065,524	-3,099,474
Acquisition of intangible assets	-266,793	-230,905	-443,199	-425,891
Restricted cash	-347,500	129,707	-417,580	-691,526
Financial (withdrawals)/contributions (securities)	2,701,455	-1,162,785	-1,863,470	-3,064,434
Receipt of charges (securities)	413,102	245,654	740,985	529,802
Debentures Acquisition	0	0	0	0
Transmission infrastructure - contractual asset	-1,847,958	-1,145,373	-4,914,868	-4,286,913
Capital acquisition/contribution of equity holdings	-340,092	-176,643	-247,695	-176,643
Disposal of equity holdings	907,500	2,449,160	3,301,759	2,449,160
Net cash in the incorporation of subsidiaries	0	1,018,193	0	0
Net cash in the acquisition of control of investees	-320,636	0	-320,636	0
Others	0	0	0	35,259
Net cash provided by investment activities of discontinued operations	0	0	0	0
Net cash provided by (used in) investing activities	2,271,877	5,851,516	-5,573,299	-8,660,320
Increase (decrease) in cash and cash equivalents	-11,726,951	10,689,488	-10,154,662	13,526,151
Cash and cash equivalents at the beginning of the period	16,387,945	5,698,457	26,572,522	13,046,371
Cash and cash equivalents at the end of the period	4,660,994	16,387,945	16,417,860	26,572,522
	-11,726,951	10,689,488	-10,154,662	13,526,151

10.5. Appendix 5 - IFRS vs. Regulatory Reconciliation

Table 39 - Reconciliation IFRS vs. regulatory (R$ thousand)

	CVM Result IFRS	Regulatory Result	Differences	CVM Result IFRS	Regulatory Result	Differences
	12/31/2025			12/31/2024
OPERATING REVENUES
Generation
Power supply for distribution companies	18,311,190	18,193,198	117,992	18,811,949	19,410,072	-598,123
Power supply for end consumers	1,760,056	1,760,056	0	2,941,312	2,941,312	0
CCEE revenue (short term market)	5,698,648	5,698,648	0	3,278,465	3,278,465	0
Operation and maintenance (O&M) revenue	1,977,831	1,977,831	0	3,063,896	3,063,896	0
Transmission
Operation and maintenance revenue	8,006,246	0	8,006,246	7,725,358	0	7,725,358
Construction revenue	4,800,378	0	4,800,378	4,161,735	0	4,161,735
Contract revenue – Transmission	7,309,163	0	7,309,163	7,405,486	0	7,405,486
Transmission System Availability (Rap)	0	18,110,274	-18,110,274	0	18,659,732	-18,659,732
Other income	541,348	541,349	0	337,166	335,343	1,823
Deductions
(-) Sector charges	-2,667,004	-2,667,003	-1	-2,484,234	-2,484,234	0
(-) ICMS	-305,303	-305,303	0	-761,342	-761,342	0
(-) PASEP e COFINS	-4,149,684	-4,149,684	0	-4,295,000	-4,295,000	0
(-) Other Deductions	-1,274	-1,274	0	-3,239	-3,239	0
Net Operating Revenue	41,281,596	39,158,092	2,123,504	40,181,552	40,145,005	36,547
OPERATING COSTS
Personnel, Material and Services	-2,633,091	-2,633,012	-79	-2,879,221	-2,878,195	-1,026
Energy purchased for resale	-6,339,557	-6,614,553	274,996	-4,992,480	-5,694,622	702,142
Charges for use of the electricity grid	-4,022,746	-3,419,338	-603,408	-3,954,730	-3,364,445	-590,285
Fuel for electricity production	-1,012,806	-1,012,806	0	-1,991,855	-1,991,855	0
Construction	-5,065,204	0	-5,065,204	-4,286,914	0	-4,286,914
Depreciation	-1,954,549	-3,783,988	1,829,439	-1,770,624	-3,211,221	1,440,597
Amortization	-2,273,425	-2,281,633	8,208	-1,946,844	-1,961,457	14,613
Operating provisions/reversals	0	0	0	0	0	0
Other costs	-263,028	-263,028	0	-277,414	-277,413	-1
Operating costs	-23,564,406	-20,008,358	-3,556,048	-22,100,082	-19,379,208	-2,720,874
GROSS PROFIT	17,717,189	19,149,733	-1,432,544	18,081,470	20,765,797	-2,684,327
OPERATING EXPENSES
Personnel, Material and Services	-3,227,060	-3,214,996	-12,064	-3,332,559	-3,397,250	64,691
Voluntary Dismissal Program	-246,700	-246,700	0	-226,815	-226,815	0
Remuneration and compensation	0	0	0	0	0	0
Depreciation	-203,749	-196,761	-6,988	-189,801	-557,024	367,223
Amortization	-145,196	-147,973	2,777	-80,506	-308,793	228,287
Donations and contributions	-68,467	-68,467	0	-145,085	-145,085	0
Operating provisions/reversals	-635,737	464,324	-1,100,061	226,600	741,999	-515,399
Result from asset sales	-7,229,469	-6,370,400	-859,069	-36,242	-36,243	1
Other expenses	-245,584	-274,150	28,566	-807,336	-816,868	9,532
OPERATING EXPENSES	-12,001,962	-10,055,123	-1,946,840	-4,591,744	-4,746,079	154,335
Regulatory Remeasurements - Transmission Contracts	-4,081,630	0	-4,081,630	6,129,771	0	6,129,771
OPERATING RESULT BEFORE FINANCIAL RESULT	1,633,597	9,094,611	-7,461,014	19,619,497	16,019,718	3,599,779
FINANCIAL RESULT	-10,926,530	-11,330,366	403,836	-11,628,120	-12,318,590	690,470
PROFIT BEFORE EQUITY HOLDINGS	-9,292,933	-2,235,756	-7,057,177	7,991,377	3,701,128	4,290,249
Equity income	1,853,984	1,113,130	740,854	2,503,205	2,050,730	452,475
Other income and expenses	459,000	459,000	0	126,201	126,201	0
OPERATING PROFIT BEFORE TAX	-6,979,949	-663,626	-6,316,323	10,620,783	5,878,059	4,742,724
Current income tax and social contribution	-333,039	-333,039	0	-717,909	-717,909	0
Deferred income tax and social contribution	13,872,646	10,883,594	2,989,052	477,879	1,881,521	-1,403,642
NET INCOME FOR CONTINUING OPERATIONS	6,559,658	9,886,928	-3,327,270	10,380,753	7,041,671	3,339,082
Portion attributable to controlling	6,558,475	9,885,688	-3,327,213	10,378,122	7,040,474	3,337,648
Portion attributable to controlling	1,183	1,240	-57	2,632	1,197	1,435
NET INCOME (LOSS) FOR DISCONTINUED OPERATIONS	0	0	0	0	0	0
Portion attributable to controlling	0	0	0	0	0	0
Portion attributable to controlling	0	0	0	0	0	0
NET INCOME FOR THE YEAR	6,559,658	9,886,928	-3,327,270	10,380,753	7,041,671	3,339,082
Portion attributable to controlling	6,558,475	9,885,688	-3,327,213	10,378,122	7,040,474	3,337,648
Portion attributable to controlling	1,183	1,240	-57	2,631	1,197	1,434

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 26, 2026

CENTRAIS ELÉTRICAS BRASILEIRAS S.A. - ELETROBRÁS

By:	/S/ Eduardo Haiama
	Eduardo Haiama Vice-President of Finance and Investor Relations

FORWARD-LOOKING STATEMENTS

This document may contain estimates and projections that are not statements of past events but reflect our management’s beliefs and expectations and may constitute forward-looking statements under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. The words “believes”, “may”, “can”, “estimates”, “continues”, “anticipates”, “intends”, “expects”, and similar expressions are intended to identify estimates that necessarily involve known and unknown risks and uncertainties. Known risks and uncertainties include, but are not limited to: general economic, regulatory, political, and business conditions in Brazil and abroad; fluctuations in interest rates, inflation, and the value of the Brazilian Real; changes in consumer electricity usage patterns and volumes; competitive conditions; our level of indebtedness; the possibility of receiving payments related to our receivables; changes in rainfall and water levels in reservoirs used to operate our hydroelectric plants; our financing and capital investment plans; existing and future government regulations; and other risks described in our annual report and other documents filed with the CVM and SEC. Estimates and projections refer only to the date they were expressed, and we do not assume any obligation to update any of these estimates or projections due to new information or future events. Future results of the Company’s operations and initiatives may differ from current expectations, and investors should not rely solely on the information contained herein. This material contains calculations that may not reflect precise results due to rounding.