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 August, 2026

Commission File Number 1-34129

AXIA Energia S.A.

(Exact name of registrant as specified in its charter)

AXIA Energia S.A.

(Translation of Registrant's name into English)

Avenida Graça Aranha, 26
Centro, CEP 20030-900
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. AXIA ENERGIA RELEASES SECOND QUARTER 2026 RESULTS	4
1.1. 2Q26 Main Events	4
1.2. 2Q26 Financial Highlights	6
2. MAIN OPERATIONAL AND FINANCIAL INDICATORS	8
3. HIGHLIGHTS OF CONSOLIDATED RESULTS	9
3.1. CONSOLIDATED RESULT \| IFRS AND REGULATORY	9
3.2. ADJUSTED CONSOLIDATED RESULT \| IFRS AND REGULATORY	11
3.2.1. Adjusted Regulatory Income Statement	11
3.2.2. Non-recurring Adjustments \| Regulatory Income Statement	12
3.2.3. Regulatory Result: Adjusted EBITDA	12
4. ENERGY TRADING	14
5. INVESTMENTS AND EXPANSION PROJECTS	15
6. INDEBTEDNESS	18
7. COMPULSORY LOAN	19
8. CASH FLOW	21
9. FINANCIAL PERFORMANCE	22
9.1. Operational and Financial Results	22
9.2. Generation Segment	24
9.3. Transmission Segment	28
9.4. Operating Costs and Expenses - IFRS	30
9.5. Equity Holdings - IFRS	34
9.6. Financial Result - IFRS	35
9.7. Current and Deferred Taxes - IFRS	36
10. OPERATIONAL PERFORMANCE	37
10.1. Generation Segment	37
10.2. Transmission Segment	40
10.3. ESG	40
11. APPENDIX	41
11.1. Appendix 1 - Generation and Transmission Revenue IFRS	41
11.2. Appendix 2 - PMSO Breakdown	42
11.3. Appendix 3 - Financing and Loans Granted (Receivables)	43
11.4. Appendix 4 - Periodic Review of the 2026 RAP for Tendered Concession Agreements	44
11.5. Appendix 5 - RAP Annual Adjustment, 2026/2027 Cycle	46
11.6. Appendix 6 - RAP Annual Adjustment - Adjustment Portion (PA), 2026/2027 Cycle	49
11.7. Appendix 7 - Transmission System Usage Tariff, 2026/2027 Cycle	51
11.8. Appendix 8 - Accounting Statements	52
11.9. Appendix 9 - IFRS vs. Regulatory Reconciliation	57

1. AXIA ENERGIA RELEASES SECOND QUARTER 2026 RESULTS

1.1. 2Q26 Main Events

2Q26 results: Reflected the positive impact of energy sales, stronger equity income, and lower provision levels. Of note, investments increased 53% YoY to R$ 3,117 million in 2Q26. These improvements reinforce Management’s continued focus on value creation, operational efficiency, and proactive contingency mitigation.

Capital Allocation Methodology: The Board of Directors approved up to R$ 3.7 billion in capital available for allocation from 2Q26 results. Combined with the previously approved 1Q26 amount of up to R$ 4.0 billion, this brings the total amount available for allocation in 1H26 to up to R$ 7.7 billion, reinforcing the Company's commitment to financial discipline and value creation for shareholders while preserving its investment capacity.

Migration to B3's Novo Mercado: In June 2026, we completed the migration to the Novo Mercado, as approved in April. This milestone represents a significant step toward simplifying the Company’s capital structure, increasing share liquidity, and continuously strengthening its corporate governance practices. As a result, the Company’s capital structure now consists exclusively of common shares (“ON”), traded under the ticker AXIA3, and Class C preferred shares (“PNC”), traded under the ticker AXIA7, which are fully convertible or redeemable through 2031.

Redemption and conversion of PNC shares: Successful completion of the first-of-its-kind redemption and conversion of PNC shares, totaling R$ 30 million. The transaction enabled the Company to assess and refine the mechanism to be used in subsequent operations.

Transmission Auction: We secured Lots 8, 9, and 10 in Transmission Auction No. 01/2026. Once commercial operations begin, these projects are expected to generate additional RAP of R$ 50.8 million, with investments of R$ 668 million, as set forth in the Auction Notice.

Investments: R$ 3,117 million in 2Q26, up 53% YoY, while in 6M26 they went up by 47% YoY to R$ 4,472 million. Notably, investments in transmission expansion increased significantly, reaching R$ 636 million this quarter as compared to R$ 85 million in 2Q25. Investments in reinforcements and improvements totaled R$ 1,073 million in 2Q26.

Still within the transmission segment, 288 large-scale projects are under implementation, representing an additional RAP of R$ 2.0 billion between 2026 and 2030 with a total estimated CAPEX of R$ 15.5 billion.

Chart 1 - Investments (R$ mm)

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

▪

Completion of the sale of a 49% minority stake in transmission special-purpose entities to GEBBRAS Participações Ltda, generating proceeds of R$ 451.4 million for AXIA Energia

▪

Completion of the acquisition of all shares held by the other partners in Juno Participações e Investimentos S.A., which holds a 50.1% interest in Tijoá Energia, for R$ 256 million. Following the transaction’s closing, AXIA Energia now fully consolidates the Três Irmãos Hydroelectric Power Plant

▪

Completion of the sale to ISA Energia of the 49% interests held by AXIA Energia and AXIA Energia Nordeste in SPE IE Madeira, as well as AXIA Energia Nordeste’s acquisition of ISA Energia’s 51% interest in SPE IE Garanhuns. Following the closing of the transaction, AXIA Energia began fully consolidating IE Garanhuns and received a net payment of R$ 1.167 billion

▪

Notice of an Extraordinary General Meeting (EGM), to be held on August 28, 2026, to deliberate on the proposed merger of the subsidiaries Juno Participações e Investimentos S.A., Tijoá Participações e Investimentos S.A., Retiro Baixo Energética S.A., and SPE Nova Era Janapu Transmissora S.A. The proposed merger is intended to consolidate operational, administrative, and tax-related activities, capture synergies and operational efficiencies, reduce costs, simplify corporate and organizational structures, accelerate decision-making, and enhance competitiveness

Financial management: net debt totaled R$ 45,461 million in 2Q26, down by R$ 585 million sequentially and up R$ 5,336 million YoY. The average debt maturity decreased by 2.7 months while the average cost went down to CDI - 0.02% p.a. in 2Q26 from CDI + 0.58% p.a. in 2Q25. Highlights include the maturity of R$ 2.2 billion in debentures in April and the raising of R$ 500 million in May 2026. In July, we also completed our 9th, 10th, and 11th issuances of simple debentures, totaling R$ 3.5 billion.

Compulsory loan: the provision inventory was reduced by R$ 1.3 billion YoY and R$ 278 million sequentially, totaling R$ 10.8 billion in 2Q26, even after considering the monetary restatement for the period. In addition, agreements reached and favorable decisions led to a net reversal of R$ 98 million in the quarter.

Adjusted Net Income, IFRS: reached R$ 1,608 million in 2Q26, broadly in line with 2Q25, as the improvement in EBITDA partially offset the weaker financial result. In 6M26, adjusted IFRS net income totaled R$ 5,315 million, compared with R$ 1,389 million in 6M25, as the improvement in EBITDA more than offset the weaker financial result.

1.2. 2Q26 Financial Highlights

Contribution margin from generation, ACL + MCP: The unit margin for energy traded in the ACL and settled in the MCP was R$ 96/MWh in 2Q26, up from R$ 73/MWh in 2Q25, considering the resources available for allocation in both segments, resulting in a contribution margin of R$ 2,329 million in the period.

The YoY improvement was explained by:

▪

Higher volume of energy available, reflecting the additional energy released for sale following the end of the quota regime and the higher GSF (99.2% in 2Q26 vs 95.6% in 2Q25)

▪

Higher short-term price (PLD) in the North, Northeast, and South submarkets, offsetting the drop in the Southeast/Central-West

▪

Higher contribution from hourly allocation of contracted volumes (modulação)

Contribution margin from transmission: R$ 4,025 million in 2Q26, in line with the R$ 3,972 million recorded in 2Q25.

The increase mainly reflected the improvement in the PA for the current tariff cycle, which shifted from a discount of R$ 382 million on revenue in 2Q25 to R$ 117 million in 2Q26. This variation was largely due to a negative component related to the postponement of the 2023 Periodic Tariff Review (RTP), pursuant to ANEEL Resolution No. 3,344/2024, which affected only the 2024/2025 tariff cycle and therefore had no corresponding impact in 2Q26.

Still in 2Q26, a provision of R$ 40 million was recognized, related to regulatory restitution assets and liabilities, arising from pass-through items amounts. In 2Q26, this provision comprised:

▪

R$ 168 million related to the recognition of a provision for pass-through items collected as part of revenue during the quarter

▪

R$ 128 million related to the reversal of the provision recognized in 1Q26, corresponding to 1/4 of the amount approved for the current tariff cycle. The provision reflects pass-through items collected during the 2024/2025 tariff cycle and returned in the current 2025/2026 cycle

This accounting practice, adopted since 1Q26 solely for regulatory reporting purposes, has no cash impact and is intended to smooth the effects on revenue of collecting and returning pass-through items across different tariff cycles, making the revenue trend more closely aligned with RAP receipts.

Adjusted PMSO:

▪

IFRS: R$ 1,471 million in 2Q26, stable when compared to R$ 1,431 million recorded in 2Q25.

▪

Regulatory: R$ 1,475 million in 2Q26, stable when compared to R$ 1,448 million recorded in 2Q25.

◦

Excluding generation costs allocated to the segment's contribution margin on a managerial basis, PMSO was R$ 1,398 million in 2Q26, stable when compared to R$ 1,381 million in 2Q25.

Adjusted Provision:

▪

IFRS: R$ 78 million provision in 2Q26, compared to a provision of R$ 177 million in 2Q25.

▪

Regulatory: R$ 35 million provision in 2Q26, compared to a R$ 98 million provision in 2Q25.

Adjusted Regulatory Equity Income: totaled positive R$ 296 million in 2Q26, compared to negative R$ 205 million in 2Q25. This variation was mainly explained by:

▪

Recognition of Equatorial Maranhão’s 2Q25 results only in 3Q25

▪

Eletronuclear's classification as asset held for sale in 3Q25

▪

Resumption of ISA Energia’s contribution to equity income

▪

IE Madeira's classification as asset held for sale in 2Q26

Adjusted Regulatory EBITDA: EBITDA reached R$ 6,683 million in 2Q26, up 21.5% YoY, driven by:

▪

A 17.5% increase in contribution margin from generation

▪

A 64.0% drop in provisions

Table 1 - Adjusted Regulatory EBITDA

	2Q26	2Q25	∆%	1Q26	∆%
Transmission - excluding non adjusted items	3,819	3,702	3.2	3,831	-0.3
Non-adjusted revenue, transmission: pass-through items and mismatches between RAP and revenue, compensated through the Adjustment Portion (PA) in the following cycle	246	270	-9.0	320	-23.3
Non-adjusted revenue, transmission: liability refund provision	-40	0	n.m.	-725	-94.4
Transmission Contribution Margin	4,025	3,972	1.3	3,426	17.5
Energy sold in regulated market (ACR) and through quota regime	1,324	1,342	-1.3	1,383	-4.2
Energy sold in free market (ACL) and liquidated in short-term market (MCP)	2,329	1,531	52.2	4,601	-49.4
Thermal power plants	0	236	-100.0	-2	-99.5
Generation Contribution Margin	3,653	3,109	17.5	5,982	-38.9
Other Revenues	143	105	36.1	133	6.9
Personnel, Materials, Services and Others (1)	-1,398	-1,381	1.2	-1,371	2.0
Costs and expenses	-1,398	-1,352	3.4	-1,371	2.0
Costs and expenses: thermal power plants	0	-29	n.m.	0	0.0
Results before Provisions and Equity Interests	6,422	5,804	10.7	8,171	-21.4
Operating Provisions	-35	-98	-64.0	-22	61.2
Results before Equity Interests	6,387	5,706	11.9	8,149	-21.6
Equity holdings	296	-205	-244.6	452	-34.5
EBITDA	6,683	5,501	21.5	8,600	-22.3

(1) PMSO, excluding other non-manageable generation costs. 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 2Q26, the adjusted regulatory PMSO under the accounting view totaled R$ 1,475 million, composed of R$ 52 million in RHR hedge costs and R$ 24 million in other generation operating costs, both allocated in the margin from generation, and R$ 1,398 million in other manageable costs and expenses components for personnel, materials, services and other. At the same time, in 2Q26, the adjusted IFRS PMSO from an accounting perspective totaled R$ 1,471 million, comprised of R$ 52 million in RHR hedge costs and R$ 24 million in other generation operating costs, both allocated to the margin from generation, and R$ 1,395 million in other manageable costs and expenses components related to personnel, materials, services, and other.

Adjusted Income and Social Contribution Taxes on Net Income, IFRS: reached R$ 94 million in 2Q26, compared to R$ 173 million in 2Q25. This variation was driven by lower deferred tax recognition, partially offset by a reduction in current tax expense, mainly reflecting a lower taxable income base at AXIA Energia Norte following the write-off of the provision for doubtful accounts related to the assignment of receivables from Amazonas Energia during the quarter.

Adjusted Net Income, IFRS: reached R$ 1,608 million in 2Q26, broadly in line with 2Q25, as the improvement in EBITDA partially offset the weaker financial result. In 6M26 this line reached R$ 5,315 million, compared with R$ 1,389 million in 6M25, as the improvement in EBITDA more than offset the weaker financial result.

2. MAIN OPERATIONAL AND FINANCIAL INDICATORS

Table 2 - Operating highlights

	2Q26	2Q25	∆%	1Q26	∆%	6M26	6M25	∆%
Generation and Trading
Installed Generation Capacity (MW)	44,430	44,368	0.1	44,026	0.9	44,430	44,368	0.1
Assured Capacity (aMW) (1)	21,548	21,655	-0.5	21,444	0.5	21,548	21,655	-0.5
Net Generation (TWh)	41.1	38.7	6.2	44.4	-7.5	85	84	1.4
Energy Sold ACR (TWh) (2)	7.5	8.7	-13.9	8.0	-6.5	16	19	-17.1
Energy Sold ACL (TWh) (3)	15.0	16.6	-9.7	14.6	3.3	30	36	-18.1
Energy Sold Quotas (TWh) (4)	2.6	4.9	-47.0	2.7	-5.1	5	10	-48.4
Average ACR Price (R$/MWh) (5)	225.74	220.97	2.2	221.67	1.8	225.74	216.59	4.2
Average ACL Price (R$/MWh)	191.11	153.67	24.4	193.02	-1.0	191.11	152.06	25.7
Transmission
Transmission lines (km)	74,829	73,774	1.4	74,829	0.0	74,829	73,774	1.4
RAP (R$ mm) (6)	16,839	17,209	-2.1	16,824	0.1	33,663	34,372	-2.1

(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) exit of Santa Cruz TPP, after the closing and conclusion of its sale in Oct/25; (g) it does not yet reflect 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

	2Q26	2Q25	∆%	1Q26	∆%	6M26	6M25	∆%
Financial Indicators
Gross Revenue (R$ mn)	12,910	12,082	6.9	14,586	-11.5	27,495	24,304	13.1
Adjusted Gross Revenue (R$ mn)	12,910	12,191	5.9	14,586	-11.5	27,495	24,413	12.6
Net Operating Revenue (R$ mn)	11,188	10,199	9.7	12,712	-12.0	23,900	20,613	15.9
Adjusted Net Operating Revenue (R$ mn)	11,188	10,308	8.5	12,712	-12.0	23,900	20,722	15.3
Regulatory Net Operating Revenue (R$ mn)	10,007	9,593	4.3	11,618	-13.9	21,625	19,300	12.0
EBITDA (R$ mn)	5,925	1,259	370.7	7,448	-20.5	13,374	5,576	139.8
Adjusted EBITDA (R$ mn)	6,307	5,151	22.5	8,540	-26.1	14,847	9,567	55.2
Regulatory EBITDA (R$ mn)	6,870	5,820	18.0	8,613	-20.2	15,483	11,305	37.0
Adjusted Regulatory EBITDA (R$ mn)	6,683	5,501	21.5	8,600	-22.3	15,283	10,878	40.5
EBITDA Margin (%)	53.0	12.3	40.6pp	58.6	-5.6pp	56.0	27.1	28.9pp
Adjusted EBITDA Margin (%)	56.4	50.0	6.4pp	67.2	-10.8pp	62.1	46.2	16.0pp
Net Income (R$ mn)	1,191	-1,325	-189.9	2,631	-54.7	3,821	-1,679	-327.6
Adjusted Net Income (R$ mn)	1,608	1,469	9.5	3,707	-56.6	5,315	1,389	282.6
Adjusted Gross Debt (R$ mn)	72,829	71,042	2.5	74,787	-2.6	72,829	71,042	2.5
Adjusted Net Debt (Adj Net Debt) (R$ mn)	45,461	40,125	13.3	46,045	-1.3	45,461	40,125	13.3
Adj Net Debt/Adjusted LTM EBITDA	1.8	1.5	19.0	1.9	-5.8	1.8	1.5	19.0
Investments (R$ mn)	3,117	2,043	52.6	1,355	130.0	4,472	3,037	47.2

3. HIGHLIGHTS OF CONSOLIDATED RESULTS

3.1. CONSOLIDATED RESULT | IFRS AND REGULATORY

Table 4 - Income statement IFRS (R$ mn)

	2Q26			2Q25		1Q26		6M26	6M25
	IFRS	Adjustment	Adjusted	Adjusted	% Y/Y	Adjusted	% Q/Q	Adjusted	Adjusted	% Y/Y
Generation	7,106	0	7,106	6,960	2.1	9,428	-24.6	16,533	13,928	18.7
Transmission	5,657	0	5,657	5,079	11.4	5,015	12.8	10,671	10,264	4.0
Others	147	0	147	152	-3.1	143	2.7	291	221	31.6
Gross Revenue	12,910	0	12,910	12,191	5.9	14,586	-11.5	27,495	24,413	12.6
(-) Deductions from Revenue	-1,721	0	-1,721	-1,883	-8.6	-1,874	-8.1	-3,595	-3,691	-2.6
Net Revenue	11,188	0	11,188	10,308	8.5	12,712	-12.0	23,900	20,722	15.3
Energy resale, grid, fuel and construction (1)	-3,705	0	-3,705	-3,540	4.7	-3,327	11.4	-7,032	-7,381	-4.7
Personnel, Material, Services and Others	-1,578	107	-1,471	-1,431	2.8	-1,441	2.1	-2,912	-2,918	-0.2
Operating provisions	-281	204	-78	-177	-56.1	-68	14.6	-145	-262	-44.7
Results from asset sale	-83	83	0	0	0.0	0	0.0	0	0	0
Regulatory remeasurements - Transmission contracts	0	0	0	0	0.0	0	0.0	0	-952	n.m.
Other income and expenses	12	-12	0	0	0.0	0	0.0	0	0	0.0
Results, before Equity holdings	5,552	382	5,934	5,160	15.0	7,876	-24.6	13,810	9,209	50.0
Equity holdings	373	0	373	-10	n.m.	664	-43.9	1,037	358	n.m.
EBITDA	5,925	382	6,307	5,151	22.5	8,540	-26.1	14,847	9,567	55.2
D&A	-1,233	0	-1,233	-1,131	9.0	-1,253	-1.6	-2,485	-2,244	10.8
EBIT	4,692	382	5,075	4,019	26.3	7,287	-30.4	12,362	7,323	68.8
Financial Result	-3,524	151	-3,373	-2,377	41.9	-3,079	9.5	-6,452	-5,696	13.3
EBT	1,169	533	1,702	1,642	3.6	4,208	-59.6	5,910	1,627	n.m.
Income Tax and Social Contribution	22	-116	-94	-173	-45.8	-501	-81.3	-595	-238	n.m.
Net Income	1,191	417	1,608	1,469	9.5	3,707	-56.6	5,315	1,389	n.m.

(1) Energy purchased for resale includes: (a) short-term purchases under contracts with terms of less than 12 months; (b) structural purchases under contracts with terms of 12 months or more; and (c) the results of agents with negative CCEE settlement balances during the period. Intercompany purchases are excluded, as they are eliminated upon consolidation.

Table 5 - Regulatory IS (R$ mn)

	2Q26			2Q25		1Q26		6M26	6M25
	Regulatory	Adjustment	Adjusted	Adjusted	% Y/Y	Adjusted	% Q/Q	Adjusted	Adjusted	% Y/Y
Generation	7,106	0	7,106	6,945	2.3	9,428	-24.6	16,533	13,968	18.4
Transmission	4,475	0	4,475	4,488	-0.3	3,921	14.1	8,396	8,911	-5.8
Others	147	0	147	152	-3.1	143	2.7	291	221	31.6
Gross Revenue	11,728	0	11,728	11,585	1.2	13,492	-13.1	25,220	23,100	9.2
(-) Deductions from Revenue	-1,721	0	-1,721	-1,883	-8.6	-1,874	-8.1	-3,595	-3,691	-2.6
Net Revenue	10,007	0	10,007	9,701	3.1	11,618	-13.9	21,625	19,409	11.4
Energy resale, grid, fuel and construction (1)	-2,110	0	-2,110	-2,450	-13.9	-2,001	5.4	-4,112	-5,582	-26.3
Personnel, Material, Services and Others	-1,582	107	-1,475	-1,448	1.9	-1,446	2.0	-2,920	-2,940	-0.7
Operating provisions	-15	-21	-35	-98	-64.0	-22	61.2	-57	-175	-67.3
Results from asset sale	261	-261	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	12	-12	0	0	0.0	0	0.0	0	0	0.0
Results, before Equity holdings	6,574	-187	6,387	5,706	11.9	8,149	-21.6	14,536	10,711	35.7
Equity holdings	296	0	296	-205	n.m.	452	-34.5	747	166	n.m.
EBITDA	6,870	-187	6,683	5,501	21.5	8,600	-22.3	15,283	10,878	40.5
D&A	-1,698	0	-1,698	-1,615	5.1	-1,696	0.1	-3,394	-3,206	5.8
EBIT	5,172	-187	4,985	3,887	28.3	6,904	-27.8	11,890	7,672	55.0
Financial Result	-3,770	372	-3,398	-2,398	41.7	-3,112	9.2	-6,510	-5,673	14.7
EBT	1,402	185	1,587	1,488	6.6	3,793	-58.2	5,380	1,999	n.m.
Income Tax and Social Contribution	90	2	92	-244	n.m.	-580	n.m.	-488	-345	41.5
Net Income	1,491	188	1,679	1,245	34.9	3,213	-47.7	4,892	1,654	n.m.

3.2. ADJUSTED CONSOLIDATED RESULT | IFRS AND REGULATORY

3.2.1. 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$ mn)

	2Q26 IFRS	Difference	2Q26 Regulatory	Non-recurring Adjustment	2Q26 Regulatory Adjusted	2Q25 Regulatory Adjusted	% Y/Y
Generation	7,106	0	7,106	0	7,106	6,945	2.3
Transmission	5,657	-1,182	4,475	0	4,475	4,488	-0.3
Others	147	0	147	0	147	152	-3.1
Gross Revenue	12,910	-1,182	11,728	0	11,728	11,585	1.2
(-) Deductions from Revenue	-1,721	0	-1,721	0	-1,721	-1,883	-8.6
Net Revenue	11,188	-1,182	10,007	0	10,007	9,701	3.1
Construction	-1,441	1,441	0	0	0	0	0.0
Energy resale	-1,300	0	-1,300	0	-1,300	-1,419	-8.4
Grid	-964	154	-811	0	-811	-809	0.2
Fuel	0	0	0	0	0	-222	n.m.
Energy resale, grid, fuel and construction (1)	-3,705	1,595	-2,110	0	-2,110	-2,450	-13.9
Personnel	-820	-2	-821	65	-756	-787	-4.0
Material	-55	0	-55	0	-55	-42	30.7
Services	-556	0	-556	42	-515	-441	16.8
Others	-148	-2	-149	0	-149	-177	-15.9
Personnel, Material, Services and Others	-1,578	-3	-1,582	107	-1,475	-1,448	1.9
Operating provisions	-281	267	-15	-21	-35	-98	-64.0
Results from asset sale	-83	344	261	-261	0	0	0.0
Regulatory remeasurements - Transmission contracts	0	0	0	0	0	0	0.0
Other income and expenses	12	0	12	-12	0	0	0.0
Results, before Equity holdings	5,552	1,022	6,574	-187	6,387	5,706	11.9
Equity holdings	373	-77	296	0	296	-205	n.m.
EBITDA	5,925	944	6,870	-187	6,683	5,501	21.5
D&A	-1,233	-465	-1,698	0	-1,698	-1,615	5.1
EBIT	4,692	480	5,172	-187	4,985	3,887	28.3
Financial Result	-3,524	-246	-3,770	372	-3,398	-2,398	41.7
EBT	1,169	233	1,402	185	1,587	1,488	6.6
Income Tax and Social Contribution	22	67	90	2	92	-244	n.m.
Net Income, continued	1,191	301	1,491	188	1,679	1,245	34.9

3.2.2. Non-recurring Adjustments | Regulatory Income Statement

The following adjustments refer to events considered non-recurring:

▪

PMSO (Personnel): R$ 65 million, of which:

▪

(+) R$ 57 million from severance costs

▪

(+) R$ 8 million from Voluntary Dismissal Plans (VDPs)

▪

PMSO (Services): R$ 42 million related to success fees tied to legal contingency reduction

▪

Operating Provisions: -R$ 21 million, including:

◦

(+) R$ 78 million relating to the compulsory loan liability, reflecting the conversion of Class B preferred shares into common shares upon the migration to B3's Novo Mercado, together with the mark-to-market effect based on the LTM average price of those shares

◦

(-) R$ 41 million in estimated losses on investments and impairment

◦

(-) R$ 30 million in provisions for litigation

◦

(-) R$ 28 million due to the reversal of provisions for onerous contracts

▪

Asset Disposal: -R$ 261 million reflecting the results of M&A processes carried out in the period. Each quarter, amounts recognized under this line item are treated as non-recurring and primarily comprise fair value adjustments arising from asset remeasurement, adjustments to amounts paid or received between contract signing and transaction closing, and transaction costs.

▪

Other Revenues and Expenses: -R$ 12 million fully adjusted as non-recurring due to the atypical nature of the underlying items. The main item was the reconciliation of judicial deposits.

▪

Financial Result: R$ 372 million, mainly comprising:

◦

(+) R$ 221 million from the monetary restatement of litigation-related amounts, excluding compulsory loan proceedings

◦

(+) R$ 151 million from the monetary restatement of compulsory loan proceedings

▪

Income Tax and Social Contribution: R$ 2 million on non-recurring items adjusted at the EBT level.

3.2.3. Regulatory Result: Adjusted EBITDA

In 2Q26, adjusted regulatory EBITDA totaled R$ 6,683 million, up R$ 1,182 million YoY, reflecting:

▪

R$ 901 million increase in generation results, excluding thermal power plants, which more than offset higher costs for energy purchased for resale and electricity grid usage charges

▪

R$ 500 million increase in equity income

▪

R$ 63 million reduction in operating provisions

These effects more than offset:

▪

R$ 228 million decline in thermal power plant results, following the completion of their divestment

▪

R$ 56 million increase in PMSO costs and expenses

▪

R$ 13 million drop in transmission revenue, notably the R$ 40 million provision related to restitution liabilities

Equity income was R$ 296 million in 2Q26, up by R$ 500 million YoY, mainly reflecting:

▪

Recognition of Equatorial Maranhão’s 2Q25 results only in 3Q25

▪

Eletronuclear's classification as asset held for sale in 3Q25

▪

Improvement of ISA Energia’s results in the period

▪

IE Madeira's classification as asset held for sale in 2Q26

It is also worth noting that if one excludes the results from the thermal power plants sold in May and October 2025, EBITDA went up R$ 1,410 million, to R$ 6,683 million in 2Q26 from R$ 5,273 million in 2Q25.

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

	2Q26	Thermal Power Plants (TPP)	2Q26 Excluding TPP	2Q25	Thermal Power Plants (TPP)	2Q25 Excluding TPP
Generation	7,106	0	7,106	6,945	740	6,205
Transmission	4,475	0	4,475	4,488	0	4,488
Others	147	0	147	152	0	152
Gross Revenue	11,728	0	11,728	11,585	740	10,845
(-) Deductions from Revenue	-1,721	0	-1,721	-1,883	-49	-1,834
Net Revenue	10,007	0	10,007	9,701	691	9,010
Energy resale, grid, fuel and construction (1)	-2,110	0	-2,110	-2,450	-434	-2,017
Personnel, Material, Services and Others	-1,475	0	-1,475	-1,448	-29	-1,418
Operating provisions	-35	0	-35	-98	0	-98
Results, before Equity holdings	6,387	0	6,387	5,706	228	5,478
Equity holdings	296	0	296	-205	0	-205
EBITDA	6,683	0	6,683	5,501	228	5,273

4. ENERGY TRADING

AXIA Energia companies sold 25.2 TWh of energy in 2Q26, down 16.9% compared to the 30.3 TWh traded in 2Q25.

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, Baguari, Retiro Baixo and Santo Antônio HPPs.

Table 8 - Energy balance 2Q26 (aMW)

	2026		2027		2028

Resources (A)	17,933		18,330		18,122
Own resources (1) (2) (3) (4)	15,541		16,731		16,726
Hydraulic	15,263		16,452		16,447
Wind	279		279		279
Energy Purchase (5)	2,391		1,599		1,396
Limit =>	Lower	Higher	Lower	Higher	Lower	Higher
Sales (B)	11,042	14,042	7,649	10,649	5,048	11,048
ACR - Except quotas	3,542		3,149		3,048
ACL - Bilateral Contracts (range) + STM implemented (5)	7,500	10,500	4,500	7,500	2,000	8,000
Average prices Contracts signed
Limit =>	Lower	Higher	Lower	Higher	Lower	Higher
Average Price of Sales Contracts (ACR and ACL - R$/MWh) (6)	190	210	200	230	190	230
Balance (A - B)	6,891	3,891	10,681	7,681	13,074	7,074
Balance considering estimated hedge (7)	4,306	1,306	7,894	4,894	10,288	4,288
Uncontracted energy considering estimated hedge (7)	24%	7%	43%	27%	57%	24%

Contracts signed until 6/30/2026.

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.

Own Resources include the decotization plants (new Independent Power Producers - 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.

Purchase balances include all energy purchased for resale: (a) short-term purchases under contracts with terms of less than 12 months and (b) structural purchases under contracts with terms of 12 months or more; Additionally, the balances include intercompany transactions, impacting both energy purchase and sales in the free market (ACL), in the following amounts: approximately 550 aMW in 2026, 500 aMW in 2027 and 150 aMW in 2028.

Average prices are gross of PIS/COFINS taxes (at 9.25%) and are not directly comparable to BBCE prices, which are net of taxes.

The figures represent an estimate of uncontracted energy. The estimated value for 2026, 2027 and 2028 is 83.1%, in line with average historical GSF from 2020 to 2025. 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 (8) (9)	2,626	1,313	0

Includes only the Assured Capacity of generation assets undergoing removal from the quota regime following the privatization of Eletrobras, now AXIA Energia. The figures exclude the Assured Capacity of the Jaguari HPP (12.7 aMW), whose concession remains under AXIA Energia’s interim management, and the Três Irmãos HPP (206.7 aMW), which has been consolidated since the completion of the acquisition of a 50.1% interest in Tijoá Energia on June 2, 2026, as disclosed in the Material Fact published on the same date.

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.

5. INVESTMENTS AND EXPANSION PROJECTS

Investments totaled R$ 3,117 million in 2Q26 and R$ 4,472 million in 6M26, representing increases of 52.6% and 47.2% compared to 2Q25 and 6M25, respectively.

Of total transmission investments, 37% was allocated to expansion projects, 36% to large-scale reinforcement and improvement projects, 26% to small-scale R&I projects, and the remaining 1% to maintenance.

The amount invested in infrastructure was allocated as follows:

▪

65% for IT

▪

23% for equipment and machinery

▪

12% 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.

A breakdown of investments by the holding company and its main subsidiaries is available in the operating data spreadsheet in the Modeling Guide section of the Company’s Investor Relations website.

Table 10 - Investments (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Generation Corporate	297	357	-16.9	185	61.0	482	524	-8.1
Implementation / Expansion	9	45	-81.1	11	-24.5	20	82	-75.7
Maintenance	289	312	-7.5	173	66.6	462	442	4.5
Transmission Corporate	1,721	1,199	43.5	977	76.1	2,698	1,854	45.5
Expansion	636	85	n.m.	263	n.m.	899	139	n.m.
Reinforcements and improvements	1,073	1,108	-3.2	691	55.3	1,764	1,704	3.5
Large-scale	622	763	-18.4	386	61.2	1,009	1,140	-11.5
Small-scale	451	346	30.4	305	47.9	756	564	34.0
Maintenance	11	5	n.m.	23	-51.6	35	11	n.m.
Infrastructure	112	117	-4.4	67	68.1	179	161	11.2
Environmental	82	67	22.4	86	-3.8	168	114	47.1
SPEs	733	225	n.m.	0	0.0	733	225	n.m.
Generation - Contributions	0	0	0.0	0	0.0	0	0	0.0
Generation - Acquisition	0	0	0.0	0	0.0	0	0	0.0
Transmission - Contributions	733	225	n.m.	0	0.0	733	225	n.m.
Transmission - Acquisition	0	0	0.0	0	0.0	0	0	0.0
Investment for Special Obligation – Itaipu HVDC	172	77	n.m.	41	n.m.	213	159	33.6
Total	3,117	2,043	52.6	1,355	n.m.	4,472	3,037	47.2

Expansion Projects - Transmission

Large-Scale Projects

▪

Projects: 288^[1], including the Itaipu HVDC System Revitalization project. The sample was increased from 286 to 288 projects during the quarter, due to the inclusion of 12 new authorizations issued by the regulator and 10 projects that were energized.

▪

Estimated investment: R$ 6.86 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$ 8.68 billion, mainly driven by:

◦

Nova Era Janapu, which was part of the sample since 2Q24

◦

Nova Era Catarina, Nova Era Ceará, Nova Era Integração and Nova Era Teresina, added in 3Q24^[2]

◦

AXIA Energia Transmissora Nova Ponte, AXIA Energia Transmissora Paracatu, AXIA Energia Transmissora Carnaúba and AXIA Energia Transmissora Seridó, included in 1Q26²

◦

The sample also includes Lots 8, 9, and 10 of Auction No. 01/2026, awarded to AXIA Energia Sul on July 3, 2026

▪

Additional associated RAP: R$ 2 billion between 2026-2030.

▪

Notably, August 3, 2026 marked the beginning of commercial operations at AXIA Energia’s Chapecoense Substation, 17 months ahead of ANEEL’s deadline. The project is part of Lot 9, awarded to the Company in ANEEL Transmission Auction No. 001/2024 and will add R$ 12.7 million to the Company’s RAP.

Small-Scale Projects

▪

Developments: 7,418 small-scale events under implementation or to be implemented, of which 7,049 were improvements and 369 were reinforcements. Data from ONS Improvement and Reinforcement Plan Management System (SGPMR).

^[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 288 projects will add 2,332 km of transmission lines and 20,616 MVA in substations.

^[2] Each of the 9 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. SPE AXIA Energia Transmissora Nova Ponte holds contract no. 006/2026-ANEEL for lot 6A of auction 04-2025; SPE AXIA Energia Paracatu holds contract no. 007/2026-ANEEL for lot 6B of auction 04-2025; SPE AXIA Energia Carnaúba holds contract no. 008/2026-ANEEL for lot 7A of auction 04-2025; and SPE AXIA Energia Seridó holds contract no. 009/2026-ANEEL for lot 7B of auction 04-2025. Lots 8, 9 and 10 of Auction No. 01/2026, awarded to AXIA Energia Sul on July 3, 2026, are expected to have their contracts signed on September 9, 2026.

Table 11 - Portfolio of ongoing transmission projects

	2Q26	2Q25	%	1Q26	%
Large Scale: Reinforcement and Improvement
Estimated Portfolio Investment (R$ bi)	6.9	7.0	-1.3	7.0	-1.3
Additional RAP associated (R$ bi)	1.1	1.1	-0.8	1.1	-2.0
# of projects in the beginning of the period	277	235	17.9	215	28.8
(-) energized	-10	-9	11.1	-11	-9.1
(-) cancelled	0	0	0.0	-1	n.m.
(+) new authorizations	9	18	-50.0	74	-87.8
# of projects in the end of the period	276	244	13.1	277	-0.4
Large Scale: Expansion (Auctions in implementation)
Estimated Portfolio Investment (R$ bi)	8.7	6.4	36.4	8.0	8.3
Additional RAP associated (R$ bi)	0.9	0.7	30.5	0.9	5.9
# of projects in the beginning of the period	9	6	50.0	9	0.0
(-) energized	0	0	0.0	0	0.0
(-) cancelled	0	0	0.0	0	0.0
(+) new authorizations	3	0	0.0	0	0.0
# of projects in the end of the period	12	6	n.m.	9	33.3
Small Scale
# of projects in the end of the period	7,418	9,194	-19.3	7,805	-5.0
Improvement	7,049	8,668	-18.7	7,399	-4.7
Reinforcement	369	526	-29.8	406	-9.1

6. INDEBTEDNESS

Net debt totaled R$ 45,461 million in 2Q26, down R$ 585 million sequentially and up R$ 5,336 million YoY. The Company's total average cost decreased to CDI - 0.02% p.a. in 2Q26 from CDI + 0.58% p.a. in 2Q25 while average debt maturity was reduced by 2.7 months vs the same period in 2025.

In April, the 3rd series of AXIA Energia’s 2nd debenture issuance and the 1st series of its 3rd debenture issuance matured, in the amounts of R$ 1.0 billion and R$ 1.2 billion, respectively. In May, AXIA Energia Norte strengthened its capital structure by raising R$ 500 million with a two-year maturity. In July, AXIA Energia completed its 9th, 10th and 11th issuances of non-convertible debentures, totaling R$ 3.5 billion, with maturities of seven and ten years.

Table 12 - Net debt (R$ mn)

	06/30/2026	03/31/2026	06/30/2025
(+) Gross Debt, including derivatives	72,829	74,787	71,042
(+) Gross Debt	70,973	73,524	70,290
(+) Derivatives (currency hedge) Net	1,857	1,263	752
(-) Cash and Cash Equivalents + Current Securities	26,229	27,677	29,387
(-) Restricted Cash for Loans and Financing	941	868	899
(-) Loans receivable	199	196	632
Net Debt	45,461	46,045	40,125
Adjusted Net Debt / Adjusted Regulatory EBITDA LTM	1.7x	1.8x	1.8x
Net Debt's Average Term (months)	53.8	54.5	56.5

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 modeling guide 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 + 0.92%	41,754	57.3
IPCA	IPCA + 5.92%	21,843	30.0
% of CDI	122% of CDI	4,965	6.8
TJLP	TJLP + 1.98%	2,644	3.6
Fixed Rate	5.52% per year	1,454	2.0
EUR	2.63% per year	169	0.2
Total		72,829	100.0

7. 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$ 1.3 billion YoY and R$ 278 million sequentially, totaling R$ 10.8 billion in 2Q26, mainly due to the settlements

▪

Net reversal of R$ 98 million due to executed agreements and favorable decisions in the quarter

▪

R$ 151 million was the amount recorded in 2Q26 under financial expenses related to monetary restatements

▪

With the execution of new agreements in 2Q26, R$ 25.2 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$ 15.1 billion, reaching R$ 10.8 billion in 2Q26, even considering the accumulated R$ 3.3 billion monetary restatement in the same period. The agreements also enabled the elimination of R$ 11.2 billion in legal risks considered "off balance", of which R$ 1.2 billion was classified as possible and R$ 10.0 billion as remote.

The significant reduction in provisions between 2022 and 2026 reflects the successful strategy of prioritizing the highest-value and most critical legal proceedings, thereby changing the risk profile of the compulsory loan portfolio.

The remaining portfolio is spread across a larger number of lower-value cases and presents less concentration risk, as most cases involving significant individual exposure have been resolved, primarily through settlements.

Following the resolution of the cases with the greatest financial impact in previous cycles, the current strategy focuses on reducing the remaining caseload. While this may result in a lower perceived impact on the provision balance, the Company continues to maintain a disciplined approach to negotiations to sustain the downward trend in provisions, mitigate risks and offset the effects of monetary restatement.

Chart 3 - Total inventory of compulsory loan provisions 2Q26 x 2Q25 (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.

Chart 4 - Total inventory of compulsory loan provisions 2Q26 x 1Q26 (R$ bn)

8. CASH FLOW

In 2Q26, the main positive cash flow drivers were:

▪

Regulatory result of R$ 6.4 billion

▪

A R$ 3.4 billion working capital release, reflecting the collection of energy revenues settled in the short-term market in 1Q26

▪

Lower litigation-related payments

These positive effects were partially offset by:

▪

Higher debt-servicing expenses

▪

Increased debt repayments and privatization-related charges

▪

Higher investments

▪

Capital contributions to investee companies

Table 14 - Cash flow (R$ mn)

	2Q26	2Q25	∆%
Adjusted Regulatory Result, before Equity Holdings	6,387	5,706	11.9
EBITDA Adjustment *	-74	319	n.m.
Income Tax and Social Contribution	-105	-39	n.m.
Working Capital	3,390	-311	n.m.
Privatization Charges	-2,299	-1,803	27.4
Dividends Received	493	249	97.8
Operating Cash Flow	7,792	4,121	89.1
Investments **	-2,834	-1,571	80.4
Free Cash Flow	4,958	2,550	94.4
Debt Service	-2,692	-1,224	n.m.
Litigation	-587	-1,346	-56.4
Guarantees and Restricted Deposits	56	545	-89.7
Supplementary social security	-84	-149	-43.9
Net Funding ***	-2,701	-1,376	96.3
Receipt of Loans and Financial Charges	1	1	-32.0
Disposal and investments of equity holdings	-682	2,021	n.m.
Dividends	-90	-1,805	-95.0
Free Net Cash	-1,821	-782	n.m.
Change in Restricted Cash (short and long term)	-171	364	n.m.
Change in Financial Investments (long-term)	39	-1	n.m.
Net Cash	-1,953	-419	n.m.

* Excludes the adjustment to the gain or loss on asset disposals line item.

** Excludes capital contributions to generation companies.

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

FINANCIAL AND OPERATIONAL RESULTS ANALYSIS

9. FINANCIAL PERFORMANCE

9.1. Operational and Financial Results

The table below presents the contribution of the AXIA Energia Group’s two main business segments—generation and transmission—based on their respective revenue and direct costs. Other costs and expenses, equity income, net financial result and taxes are analyzed on a consolidated basis.

Table 15 - Income statement 2Q26 (R$ mn)

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	12,910	-1,182	11,728	0	11,728	7,106	4,741	147	-266
(-) Deductions	-1,721	0	-1,721	0	-1,721	-1,000	-717	-5	0
Net Revenue	11,188	-1,182	10,007	0	10,007	6,106	4,025	143	-266
Energy purchased for resale (2)	-1,300	0	-1,300	0	-1,300	-1,300	0	0	0
Charges on use of the electricity grid	-964	154	-811	0	-811	-1,077	0	0	266
Fuel for electricity production (net of CCC)	0	0	0	0	0	0	0	0	0
Other Non-manageable Generation Costs (3)	-76	0	-76	0	-76	-76	0	0	0
Construction costs	-1,441	1,441	0	0	0	0	0	0	0
Regulatory remeasurements	0	0	0	0	0	0	0	0	0
Contribution Margin	7,407	414	7,820	0	7,820	3,653	4,025	143	0
PMSO, excluded Other Generation Costs (3)	-1,502	-3	-1,505	107	-1,398
Provisions	-281	267	-15	-21	-35
Results from asset sale	-83	344	261	-261	0
Other income and expenses	12	0	12	-12	0
Results, before Equity holdings	5,552	1,022	6,574	-187	6,387
Equity holdings	373	-77	296	0	296
EBITDA	5,925	944	6,870	-187	6,683
D&A	-1,233	-465	-1,698	0	-1,698
EBIT	4,692	480	5,172	-187	4,985
Financial Result	-3,524	-246	-3,770	372	-3,398
EBT	1,169	233	1,402	185	1,587
Income Tax and Social Contribution	22	67	90	2	92
Net Income	1,191	301	1,491	188	1,679

(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 2Q26 is R$ 4,741 million, and including the accounting elimination of R$ 266 million, this translates into accounting revenue of R$ 4,475 million. In the case of generation connection charges costs, for management purposes, the amount in 2Q26 is R$ 1,077 million, and including the accounting elimination of R$ 266 million, this translates into an accounting cost of R$ 811 million.

(2) Energy purchased for resale includes: (a) short-term purchases under contracts with terms of less than 12 months; (b) structural purchases under contracts with terms of 12 months or more; and (c) the results of agents with negative CCEE settlement balances during the period. Intercompany purchases are excluded, as they are eliminated upon consolidation.

(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 2Q26, the adjusted regulatory PMSO under the accounting view totaled R$ 1,475 million, composed of R$ 52 million in RHR hedge costs and R$ 24 million in other generation operating costs, both allocated in the margin from generation, and R$ 1,398 million in other manageable costs and expenses components for personnel, materials, services and other. At the same time, in 2Q26, the adjusted IFRS PMSO from an accounting perspective totaled R$ 1,471 million, comprised of R$ 52 million in RHR hedge costs and R$ 24 million in other generation operating costs, both allocated to the margin from generation, and R$ 1,395 million in other manageable costs and expenses components related to personnel, materials, services, and other.

Table 16 - Income statement 2Q25 (R$ mn)

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	12,082	-606	11,476	109	11,585	6,945	4,760	152	-273
(-) Deductions	-1,883	0	-1,883	0	-1,883	-1,047	-789	-47	0
Net Revenue	10,199	-606	9,593	109	9,701	5,898	3,972	105	-273
Energy purchased for resale (2)	-1,327	-92	-1,419	0	-1,419	-1,419	0	0	0
Charges on use of the electricity grid	-955	146	-809	0	-809	-1,082	0	0	273
Fuel for electricity production (net of CCC)	-222	0	-222	0	-222	-222	0	0	0
Other Non-manageable Generation Costs (3)	-66	0	-66	0	-66	-66	0	0	0
Construction costs	-1,036	1,036	0	0	0	0	0	0	0
Regulatory remeasurements	-3,433	3,433	0	0	0	0	0	0	0
Contribution Margin	3,160	3,916	7,076	109	7,185	3,109	3,972	105	0
PMSO, excluded Other Generation Costs (3)	-1,593	-16	-1,609	228	-1,381
Provisions	-133	130	-3	-95	-98
Results from asset sale	-105	610	504	-504	0
Other income and expenses	57	0	57	-57	0
Results, before Equity holdings	1,385	4,640	6,025	-319	5,706
Equity holdings	-126	-78	-205	0	-205
EBITDA	1,259	4,561	5,820	-319	5,501
D&A	-1,131	-483	-1,615	0	-1,615
EBIT	127	4,078	4,206	-319	3,887
Financial Result	-2,555	-73	-2,627	229	-2,398
EBT	-2,427	4,006	1,578	-90	1,488
Income Tax and Social Contribution	1,102	-1,432	-330	86	-244
Net Income	-1,325	2,573	1,248	-4	1,245

(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 2Q25 is R$ 4,760 million, and including the accounting elimination of R$ 273 million, this translates into accounting revenue of R$ 4,488 million. In the case of generation connection charges costs, for management purposes, the value in 2Q25 is R$ 1,082 million, and including the accounting elimination of R$ 273 million, this translates into an accounting cost of R$ 809 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 2Q25, the adjusted regulatory PMSO under the accounting view totaled R$ 1,448 million, composed of R$ 45 million in RHR hedge costs and R$ 21 million in other generation operating costs, both allocated in the margin from generation, and R$ 1,381 million in other manageable costs and expenses components for personnel, materials, services and others. At the same time, in 2Q25, the adjusted IFRS PMSO from an accounting perspective totaled R$ 1,431 million, comprised of R$ 45 million in RHR hedging costs and R$ 21 million in other generation operating costs, both allocated to the margin from generation, and R$ 1,365 million in other manageable costs and expenses components related to personnel, materials, services, and others.

9.2. Generation Segment

Revenue by Contracting Environment

Recurring regulatory revenue was R$ 7,106 million in 2Q26, in line with adjusted IFRS generation revenue. In 2Q25, recurring regulatory revenue was R$ 6,945 million, R$ 15 million less than the adjusted IFRS generation revenue. This difference reflected the accounting treatment of the portion of revenue from Amazonas Energia related to previously unpaid amounts, following a change in the assessment of receivables. Under IFRS, these amounts were recognized as revenue, while under regulatory accounting—where such recognition had already occurred—there was also a reversal of the provision recorded at that time. The difference, which had been recognized in previous comparison periods, had the same nature at that time.

Regulatory revenue in the regulated market was R$ 1,657 million in 2Q26, down 30% from the R$ 2,365 million recorded in 2Q25, with two main factors contributing to this:

▪

A R$ 740 million reduction reflecting the absence in 2Q26 of revenue from thermal power plant energy sales, following the divestment completed on October 9, 2025

▪

A R$ 40 million^[4] provision recorded in 2Q26 related to reimbursements to counterparties under availability contracts in the regulated market (ACR) and reserve energy, due to underdelivery of contracted wind energy as a result of insufficient generation

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

Revenue Generation	Volume (aMW) (a)			Price (R$/MWh) (b)			Regulatory Revenue (c) = (a) x (b)
Revenue Generation	2Q26	% Y/Y	% Q/Q	2Q26	% Y/Y	% Q/Q	2Q26	% Y/Y	% Q/Q
(+) Regulated Market	3,442	-13.9	-7.5	220	-18.6	1.4	1,657	-30.0	-5.2
Existing	3,320	1.3	-7.6	225	2.9	1.8	1,631	4.2	-4.8
Reimbursement from ACR-d and CER (1)	0	0.0	0.0	0	0.0	0.0	-40	0.0	18.0
M&As (2)	122	35.1	-6.3	246	-19.9	1.6	66	8.2	-3.8
Thermal	0	-100.0	0.0	0	0.0	0.0	0	-100.0	0.0
(+) Free Market	6,883	-9.7	2.1	191	24.4	-1.0	2,873	12.3	2.2
Existing	6,830	-10.4	2.3	191	24.4	-1.0	2,851	11.5	2.4
M&As (2)	53	0.0	-17.0	185	0.0	1.3	21	0.0	-15.0
(+) O&M (Quotas)	1,192	-47.0	-6.1	109	4.6	8.8	283	-44.5	3.2
Existing	1,133	-49.6	-10.8	103	-0.7	3.3	255	-50.0	-6.8
M&As (2)	59	0.0	0.0	213	0.0	0.0	28	0.0	0.0
(+) ST Market (CCEE) (4)	5,111	27.7	-18.4	205	18.6	-39.5	2,294	51.5	-50.1
(=) Revenue with energy sold	16,628	-6.9	-7.6	196	9.9	-19.3	7,106	2.3	-24.6
(+) Other	—	—	—	—	—	—	0	-100.0	0.0
(=) Total Revenue	—	—	—	—	—	—	7,106	3.9	-24.6
Recurring	—	—	—	—	—	—	7,106	2.3	-24.6
Non-recurring	—	—	—	—	—	—	0	n.m.	0.0

^[4] Amount related to impact on gross revenue. The impact on net revenue was R$ 36 million.

Revenue Generation	Regulatory Revenue (c)			Accounting Adjustment (d) (5)			Accounting Revenue (e) = (c) + (d)
Revenue Generation	2Q26	2Q25	1Q26	2Q26	2Q25	1Q26	2Q26	2Q25	% Y/Y	1Q26	% Q/Q
Regulated Market	1,657	2,365	1,748	0	15	0	1,657	2,381	-30.4%	1,748	-5.2
Free Market	2,873	2,557	2,810	0	0	0	2,873	2,557	12.3%	2,810	2.2
O&M (Quotas)	283	510	274	0	0	0	283	510	-44.5%	274	3.2
Short-term market (4)	2,294	1,514	4,596	0	0	0	2,294	1,514	51.5%	4,596	-50.1
Energy Sales	7,106	6,946	9,428	0	15	0	7,106	6,962	2.1%	9,428	-24.6
Others	0	-111	0	0	0	0	0	-111	-100.0%	0	0.0
Total Revenue	7,106	6,836	9,428	0	15	0	7,106	6,851	3.7%	9,428	-24.6
Recurring	7,106	6,945	9,428	0	15	0	7,106	6,960	2.1%	9,428	-24.6
Non-recurring	0	-109	0	0	0	0	0	-109	n.m.	0	0.0

(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 ownership interest changed during the previous 12 months. In 2Q26, the R$ 66 million M&A contribution to regulated market revenue reflects the consolidation of the Três Irmãos HPP following the acquisition, completed on June 2, 2026, of all shares in Juno Participações e Investimentos S.A. held by its former shareholders. Juno held a 50.1% controlling interest in Tijoá Energia, while AXIA Energia already held the remaining 49.9%. Tijoá Energia holds the concession for the Três Irmãos HPP.

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

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

Regulatory Margin from Generation

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

The contribution of generation to the results increased to R$ 3,653 million in 2Q26 from R$ 3,109 million in 2Q25. This result primarily reflects the higher contribution from energy sales in the free market (ACL) and settlements in the short-term market (MCP). This increase more than offset lower sales from thermal power plants and the reduced contribution from energy remunerated under the quota regime, reflecting the removal from this regime of plants whose concessions were renewed following privatization.

The main drivers for the MCP result are:

▪

Higher volume of energy available, reflecting the additional energy released for sale following the end of the quota regime along with higher GSF (99.2% in 2Q26 vs 95.6% in 2Q25)

▪

Higher short-term price (PLD) in the North, Northeast, and South submarkets, offsetting the drop in the Southeast/Central-West

▪

Higher contribution from hourly allocation of contracted volumes (modulação)

In unit terms, the margin by volume of available energy (energy resource) increased to R$ 106/MWh in 2Q26 from R$ 90/MWh in 2Q25.

It is worth noting that, when excluding the thermal power plant results (Table 19), the unit contribution margin rose to R$ 106/MWh in 2Q26 from R$ 86/MWh in 2Q25, while energy resources increased in the period, up to 15,767 aMW from 15,310 aMW.

Considering only the energy traded in the ACL and settled in the MCP, the contribution margin increased to
R$ 96/MWh in 2Q26 from R$ 73/MWh in 2Q25, resulting in a contribution margin of R$ 2,329 million.

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

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Gross Revenue	7,106	6,945	2.3	9,428	-24.6	16,533	13,968	18.4
Taxes	-636	-671	-5.2	-706	-10.0	-1,342	-1,392	-3.6
Sector charges	-364	-376	-3.2	-398	-8.4	-762	-686	11.1
Net Revenue	6,106	5,898	3.5	8,323	-26.6	14,429	11,890	21.4
Energy purchased for resale (1)	-1,300	-1,419	-8.4	-1,226	6.0	-2,526	-3,142	-19.6
Charges on use of the electricity grid (2)	-1,077	-1,082	-0.5	-1,038	3.7	-2,115	-2,204	-4.0
Fuel for electricity production (net of CCC (3))	0	-222	n.m.	-2	-99.5	-2	-782	-99.8
Other Non-manageable Generation Costs	-76	-66	15.2	-75	1.7	-151	-123	23.1
GSF Insurance (4)	-52	-45	15.5	-53	-2.3	-105	-81	29.1
Others (5)	-24	-21	14.6	-22	11.5	-46	-41	11.3
Contribution Margin	3,653	3,109	17.5	5,982	-38.9	9,635	5,639	70.9
Resources (MWm) (6)	15,767	15,786	-0.1	17,522	-10.0	16,640	17,327	-4.0
Unit Margin (R$/MWh)	106	90	17.7	158	-32.9	133	75	77.9

(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$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Gross Revenue	7,106	6,205	14.5	9,428	-24.6	16,533	11,937	38.5
Taxes	-636	-622	2.2	-706	-10.0	-1,342	-1,273	5.4
Sector charges	-364	-377	-3.3	-398	-8.4	-762	-686	11.1
Net Revenue	6,106	5,207	17.3	8,323	-26.6	14,429	9,977	44.6
Energy purchased for resale (1)	-1,300	-1,272	2.2	-1,226	6.0	-2,526	-2,679	-5.7
Charges on use of the electricity grid (2)	-1,077	-995	8.2	-1,038	3.7	-2,115	-1,987	6.5
Fuel for electricity production (net of CCC (3))	0	0	0.0	0	0.0	0	0	0.0
Other Non-manageable Generation Costs	-76	-66	15.2	-75	1.7	-151	-123	23.1
GSF Insurance (4)	-52	-45	15.5	-53	-2.3	-105	-81	29.1
Others (5)	-24	-21	14.6	-22	11.5	-46	-41	11.3
Contribution Margin	3,653	2,873	27.2	5,984	-38.9	9,637	5,189	85.7
Resources (MWm) (6)	15,767	15,310	3.0	17,522	-10.0	16,640	16,738	-0.6
Unit Margin (R$/MWh)	106	86	23.5	158	-32.9	133	71	86.8

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

(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 - adjusted contribution margin, regulatory - by contracting environment (R$ mn)

	2Q26					2Q25		1Q26
	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	7,106	0	274	1,748	5,084	4,051	25.5	7,406	-31.3
(-) Adjustment	0	0	0	0	0	0	0.0	0	0.0
Adjusted Gross Revenue	7,106	0	274	1,748	5,084	4,051	25.5	7,406	-31.3
(-) Taxes	-636	0	-24	-156	-455	-407	11.7	-555	-18.0
(-) Sector Charges	-364	0	-25	-87	-252	-231	8.7	-287	-12.4
(-) Energy purchased for resale (1)	-1,300	0	0	0	-1,300	-1,272	2.2	-1,226	6.0
(-) Charges on use of the electricity grid (2)	-1,077	0	-89	-256	-732	-595	23.0	-720	1.7
(-) Fuel for electricity production (3)	0	0	0	0	0	0	0.0	0	0.0
(-) Other Non-manageable Generation Costs	-76	0	-1	-58	-17	-14	25.2	-17	1.6
GSF Insurance (4)	-52	0	0	-52	0	0	0.0	0	0.0
Others (5)	-24	0	-1	-6	-17	-14	25.2	-17	1.6
Contribution Margin (f)	3,653	0	134	1,190	2,329	1,531	52.2	4,601	-49.4

	Own Resources (MWm)				14,479	14,820	-2.3	16,267	-11.0
	(-) Quotas				-1,192	-2,248	-47.0	-1,270	-6.1
	(-) ACR (includes thermal plants)				-3,442	-3,993	-13.8	-3,720	-7.5
	(+) Structural Purchases				1,288	966	33.3	1,255	2.6
	Resources (MWm) (6)				11,133	9,544	16.6	12,532	-11.2
	Resources (MWh thousand) (6) (g)				24,315	20,845	16.6	27,070	-10.2

	R$/MWh (f)/(g)				96	73	30.4	170	-43.6

(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.

9.3. 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, for which transmission companies act solely as collection agents, and mismatches between approved RAP and billed revenue, both compensated in the following tariff cycle through the PA

Net revenue does not include accounting eliminations relating to the intercompany portion of Transmission System Usage Charges (EUST) paid by AXIA Energia's generation companies to transmission companies within the Group. Deductions include taxes (PIS/COFINS, ICMS and ISS) and sector charges (CDE, PROINFA, TFSEE, R&D and RGR).

Provision related to regulatory restitution assets and liabilities: accounting practice

In 1Q26, the Company started recognizing in the transmission margin a provision for restitution assets and liabilities arising from pass-through items or tariff differences collected through revenue. These amounts do not belong to the Company, which acts solely as a collection agent and returns them through PA Measurement (PA Apuração) in the subsequent tariff cycle, in accordance with the existing mechanism.

This provision will be reversed when the compensation for these items, classified under PA Measurement or PA Other Adjustments (PA Outros Ajustes), is effectively recognized in revenue in the subsequent tariff cycle.

This practice has no cash impact. Its purpose is to smooth revenue recognition across different tariff cycles, aligning it more closely with the RAP collection profile. This treatment applies only for regulatory reporting purposes, as under IFRS the collection and subsequent return of pass-through items are already reflected in the contract asset recognized on the balance sheet.

Provision related to regulatory restitution assets and liabilities: recognition in 2Q26

The amount recognized in 2Q26 was R$ 40 million, consisting of:

▪

R$ 168 million related to the recognition of a provision for pass-through items collected through revenue during 2Q26

▪

R$ 128 million related to the reversal of the provision recorded in 1Q26, equivalent to 1/4 of the amount approved for the current tariff cycle and reflecting the pass-through items collected in the 2024/25 tariff cycle and returned in the 2025/26 cycle

From 2Q26 onward, provisions will reflect the pass-through items collected in each quarter and will be reversed in the subsequent tariff cycle as the corresponding deduction is recognized in revenue under PA Measurement.

Net Regulatory Revenue

Net regulatory transmission revenue totaled R$ 4,025 million in 2Q26, remaining stable YoY, primarily due to a reduction in negative PA in the current tariff cycle. This reduction mainly reflected the absence in 2Q26 of the negative component recognized in 2Q25 in connection with the postponement of the 2023 Periodic Tariff Review (RTP), pursuant to ANEEL Resolution No. 3,344/2024, which applied exclusively to the 2024/25 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 RTP

▪

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

▪

Other effects, including mismatches between the approved RAP for facilities used exclusively by distribution companies and the amounts actually received following subsequent tariff adjustments related to those facilities, as well as changes in the RAP under bilateral transmission system connection agreements

Additional details and explanations, including an analysis of transmission revenue and a breakdown of the Adjustment Portion (PA), are available in the “Modeling Support – Transmission” spreadsheet in the Results Center section of the Company's Investor Relations website.

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

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
RAP (1)	4,134	4,246	-2.6	4,134	0.0	8,269	8,491	-2.6
PA (1)	-117	-382	-69.5	-117	0.0	-233	-764	-69.5
Approved RAP and Adjustment Portion	4,018	3,864	4.0	4,018	0.0	8,036	7,727	4.0
Taxes and Sector Charges (2)	561	585	-4.2	574	-2.3	1,134	1,173	-3.3
Unavailability Discount (3)	-65	-64	0.7	-66	-1.6	-131	-131	0.1
RAP Addition: new facilities	68	40	68.1	56	21.4	124	71	75.6
Pass-through items and mismatches between RAP and billed revenue (4)	246	270	-9.0	320	-23.3	566	477	18.6
Reimbursement asset and liability provision (5)	-40	0	0.0	-725	-94.4	-766	0	0.0
Other mismatches (6)	-46	65	n.m.	9	n.m.	-36	140	n.m.
Gross Revenue (7)	4,741	4,760	-0.4	4,186	13.3	8,927	9,457	-5.6
Tributes	-454	-457	-0.7	-474	-4.2	-928	-863	7.5
Sector Charges (8)	-263	-332	-20.8	-286	-8.1	-549	-670	-18.2
Net Revenue	4,025	3,972	1.3	3,426	17.5	7,451	7,924	-6.0

(1) RAP and PA: Considers 1/4 of the amounts approved for the tariff cycle in effect during the quarter, as well as proportional amounts accrued throughout the year.
(2) Includes (a) PIS/COFINS and (b) CDE/Proinfa. Both are pass-through costs, collected by AXIA Energia 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 to be deducted in Adjustment Portion (PA) in the following tariff cycle, divided into two groups:
(4.a) Pass-through items, for which transmission companies act solely as collection agents: (i) apportionment of prepayment and deferrals; (ii) transfers to the CDE Fund related to uncollected grid usage charges; and (iii) complementary credit notices (AVCs) associated with the termination of Transmission System Use Contracts (CUST) by generators.
(4.b) Mismatches between the approved RAP and billing carried out by the ONS through AVCs, associated with: (i) Basic Border Network and other Shared Transmission Facilities (DIT); and (ii) (DIT) exclusively used by Itaipu.
(5) Provision related exclusively to pass-through items for which transmission companies act solely as collection agents (item 4.a), to be deducted through the PA in the following tariff cycle. The reversal of such provisions occurs when the correspondingPA deduction is effectively recognized in the income statement in the subsequent cycle.
(6) Other mismatches relative to the approved RAP for the current tariff cycle, including: (a) mismatches between Transmission and Distribution Annual Adjustments; (b) bilateral Transmission Connection Contracts (CCT), and (c) other diverse effects, each with limited individual impact.
(7) Does not consider the accounting elimination effect of charges paid to the Company's own transmission segment. Eliminations refer to transactions between companies within the same group, i.e., AXIA Energia companies. These include transmission system usage charges paid by the Company’s generation companies to its transmission companies, which are received as RAP. For consolidation purposes, such amounts are eliminated from transmission revenue and generation usage costs.
(8) Sector Charges includes: RGR, R&D, TFSEE, CDE, and Proinfa.

Key events in the Transmission Segment

During the quarter, four key events stood out in the transmission segment:

▪

Periodic Review of the 2026 RAP for Tendered Concession Agreements

▪

Annual RAP Adjustment for the 2026/27 Cycle

▪

Annual RAP Adjustment—Adjustment Portion (PA)—for the 2026/27 Cycle

▪

Transmission System Usage Charge for the 2026/27 Cycle

These events relate to the determination of the RAP under transmission concession agreements for the 2026/27 cycle.

Additional information is available in Appendices 4, 5, 6 and 7 at the end of this report.

9.4. Operating Costs and Expenses - IFRS

Table 22 - Operating costs and expenses (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Energy purchased for resale (1)	1,300	1,327	-2.1	1,226	6.0	2,526	2,867	-11.9
Charges on use of the electricity grid	964	955	1.0	927	4.0	1,892	1,951	-3.0
Fuel for electricity production	0	222	n.m.	2	-99.5	2	782	-99.8
Construction	1,441	1,036	39.2	1,172	23.0	2,613	1,781	46.7
Personnel, Material, Services and Others	1,578	1,659	-4.9	1,465	7.8	3,043	3,337	-8.8
Depreciation and Amortization	1,233	1,131	9.0	1,253	-1.6	2,485	2,244	10.8
Operating provisions	281	133	n.m.	520	-45.9	802	260	n.m.
Result from asset sale	83	105	-21.2	803	-89.7	886	105	n.m.
Regulatory remeasurements	0	3,433	n.m.	0	0.0	0	4,385	n.m.
Costs and expenses	6,881	10,002	-31.2	7,368	-6.6	14,249	17,712	-19.6
*Non-recurring events*
(-) Non-recurring PMSO events	-107	-228	-53.0	-23	n.m.	-130	-419	-68.9
(-) Non-recurring provisions	-204	43	n.m.	-453	-55.0	-657	3	n.m.
(-) Result from asset sale	-83	-105	-21.2	-803	-89.7	-886	-105	n.m.
(-) Regulatory remeasurements	0	-3,433	n.m.	0	0.0	0	-3,433	n.m.
Adjusted Costs and Expenses	6,487	6,279	3.3	6,089	6.5	12,575	13,757	-8.6

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$ 754 million in 2Q26, down R$ 30 million when compared to the R$ 784 million in 2Q25, with the main effects being:

◦

R$ 90 million decrease due to the higher capitalization of personnel costs, reflecting increased investment activity during the period

◦

R$ 37 million increase in variable compensation, reflecting changes implemented in late 2025 to the profit-sharing (PLR) and long-term incentive (ILP) programs to strengthen the alignment of performance and value creation with the Company’s strategic priorities

◦

R$ 25 million increase in compensation, payroll charges and benefits, mainly due to higher headcount and compensation adjustments under the newly negotiated Collective Bargaining Agreement

◦

Non-recurring effects: R$ 65 million, being:

◦

R$ 57 million from severance costs

◦

R$ 8 million from VDPs

▪

Materials: adjusted balance of R$ 55 million in 2Q26, up R$ 13 million when compared to the R$ 42 million recorded in 2Q25, mainly explained by:

◦

R$ 8 million increase in expenses related to contractual adjustments and increases in fuel prices

◦

R$ 6 million increase in maintenance expenses due to a greater concentration of maintenance activities in 2Q26, compared with 2025, when such activities were concentrated in 1Q25

There were no non-recurring effects in the quarter.

▪

Services: adjusted balance of R$ 515 million in 2Q26, up R$ 74 million when compared to the R$ 441 million in 2Q25, driven by:

◦

R$ 28 million increase in expenses due to the expanded scope of operational maintenance contracts with suppliers, reflecting the addition of new safety requirements and a greater concentration of maintenance activities in 2Q26, compared with 2025, when such activities were concentrated in 1Q25

◦

R$ 23 million increase in marketing expenses, related to rebranding

◦

R$ 10 million in higher expenses related to strengthening the cloud IT infrastructure

◦

R$ 10 million increase in real estate expenses, reflecting contractual adjustments and an increase in the scope of services provided by outsourced teams

◦

Non-recurring effects: R$ 42 million related to success fees paid to legal defense as part of the contingency reduction strategy.

▪

Other: adjusted balance of R$ 148 million in 2Q26, down R$ 17 million when compared to the R$ 164 million in 2Q25, notably:

◦

R$ 21 million reduction in judicial expenses

◦

R$19 million increase in expenses due to increased sponsorships, as a result of the rebranding

There were no non-recurring effects in the quarter.

For additional 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$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Personnel	811	899	-9.8	746	8.7	1,557	1,755	-11.3
VDP	8	98	-91.4	8	3.9	16	194	-91.5
Material	55	42	31	49.8	10.0	104.6	94	11.6
Services	556	456	22.0	434	28.2	991	894	10.8
Others	148	164	-10.3	227	-34.9	374	401	-6.7
other non-manageable generation costs	76	66	15.2	75	1.7	151	123	23.1
other manageable expenses	71	98	-27.4	152	-52.9	223	278	-19.9
PMSO (a)	1,578	1,659	-4.9	1,465	7.8	3,043	3,337	-8.8
Personnel	-57	-115	-50.5	-6	n.m.	-64	-169	-62.3
VDP	-8	-98	-91.4	-8	3.9	-16	-194	-91.5
Material	0	0	0.0	0	0.0	0	0	0.0
Services	-42	-15	n.m.	-6	n.m.	-47	-57	-16.9
Others	0	0	0.0	-3	n.m.	-3	0	0.0
other non-manageable generation costs	0	0	0.0	0	0.0	0	0	0.0
other manageable expenses	0	0	0.0	-3	n.m.	-3	0	0.0
Non recurring (b)	-107	-228	-53.0	-23	n.m.	-130	-419	-68.9
Personnel	754	784	-3.8	740	2.0	1,494	1,586	-5.8
VDP	0	0	0.0	0	0.0	0	0	0.0
Material	55	42	30.7	50	10.0	105	94	11.6
Services	515	441	16.8	429	20.1	943	837	12.7
Others	148	164	-10.3	223	-34.0	371	401	-7.5
other non-manageable generation costs	76	66	15.2	75	1.7	151	123	23.1
other manageable expenses	71	98	-27.4	149	-51.9	220	278	-21.0
PMSO adjusted (c) = (a) + (b)	1,471	1,431	2.8	1,441	2.1	2,912	2,918	-0.2
PMSO excluding TPP * (c.1)	1,471	1,402	4.9	1,441	2.1	2,912	2,852	2.1
manageable expenses	1,395	1,336	4.4	1,366	2.1	2,761	2,729	1.2
non-manageable costs: generation segment **	76	66	15.2	75	1.7	151	123	23.1
Thermal Power Plants (c.2)	0	29	n.m.	0	0.0	0	66	n.m.

* 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, Asset Disposal Result, and Other Operating Income and Expenses

▪

Regulatory Remeasurement - Transmission Contracts: There were no recognitions in this line in 2Q26.

▪

Asset disposal result: R$ 83 million expense in 2Q26, primarily related to:

◦

R$ 217 million in expenses arising from the fair value adjustment of the Company’s minority interests in transmission SPEs sold to GEBBRAS Participações Ltda on July 15, 2026

◦

R$ 192 million gain arising from the remeasurement of the Company’s stake in Tijoá Energia, the concessionaire of the Três Irmãos HPP, following completion of the acquisition on June 2, 2026

◦

R$ 58 million in other M&A-related expenses incurred during the period

▪

Other Revenues and Expenses: revenue of R$ 12 million in 2Q26, mainly from the reconciliation of judicial deposits

Operating Provisions

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

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Operating Provisions / Reversals
Provision/Reversal for Litigation	-192	22	n.m.	-349	-45.2	-541	-86	n.m.
Estimated losses on investments	41	21	92.4	10	n.m.	51	34	49.9
Measurement at fair value of assets held for sale	0	0	0.0	0	0.0	0	0	0.0
Provision for Share Conversion - Compulsory Loan	-78	-20	n.m.	-141	-44.6	-220	6	n.m.
ECL - Loans and financing	0	-10	-99.8	0	-85.7	0	-10	-98.3
ECL - Consumers and resellers	12	-79	n.m.	-7	n.m.	5	-98	n.m.
ECL - Other credits	-18	-26	-29.8	10	n.m.	-8	-33	-76.9
Onerous contracts	28	30	-3.6	28	0.0	57	59	-2.8
Results of actuarial reports	-82	-92	-10.8	-82	0.0	-163	-185	-11.6
Other (1)	7	20	-64.6	11	-35.0	18	53	-66.8
Operating Provisions / Reversals	-281	-133	n.m.	-520	-45.9	-802	-260	n.m.
*Non-recurring items / Adjustments*	204	-43	n.m.	453	-55.0	657	-3	n.m.
Provision for Litigation	192	-22	n.m.	349	-45.2	541	86	n.m.
Estimated losses on investments	-41	-21	92.4	-10	n.m.	-51	-34	49.9
Provision for Share Conversion - Compulsory Loan	78	20	n.m.	141	-44.6	220	-6	n.m.
Onerous contracts	-28	-30	-3.6	-28	0.0	-57	-59	-2.8
Impairment	4	0	0.0	0	0.0	4	0	0.0
Adjusted Provisions/Reversals	-78	-177	-56.1	-68	14.6	-145	-262	-44.7

Positive values in the table above indicate reversal of provision. (1) Primarily includes impairment and RGR refunds.

▪

Provision for litigation: provision of R$ 192 million in 2Q26 compared to a reversal of R$ 22 million in 2Q25. The R$ 214 million variation was explained by:

◦

Compulsory Loan: Contributed a net reversal of R$ 98 million in 2Q26, compared to the net reversal of R$ 246 million in 2Q25, reflecting the lower average ticket of cases settled through legal agreements. It is worth noting that, unlike other provisions, the monetary restatement related to the compulsory loan provision is recognized under financial results.

◦

Other events, unrelated to compulsory loan proceedings, contributing to results as follows:

•

Changes in provision balances: provision of R$ 69 million in 2Q26, in line with 2Q25

•

Monetary restatement: R$ 221 million expense in 2Q26 compared to R$ 51 million in 2Q25, mainly due to updates to inflation adjustment indices.

▪

Share conversion process – Compulsory Loan: R$ 78 million provision in 2Q26, compared to a R$ 20 million provision in 2Q25. This result reflects the impact from the conversion of Class B preferred shares into common shares upon the migration to B3's Novo Mercado, together with the mark-to-market effect based on the LTM average price of those shares.

▪

Expected Credit Losses (ECL) - Consumers and Resellers: reversal of R$ 12 million in 2Q26, compared to a provision of R$ 79 million in 2Q25 due to the recognition, in 2Q25, of R$ 81 million related to Amazonas Energia, without a corresponding entry in 2Q26.

9.5. Equity Holdings - IFRS

The main highlights of equity income were as follows:

▪

Transnorte Energia (TNE): The improvement in 2Q26 reflects the negative impact recorded in 2Q25 following the revision of CAPEX used to calculate the return on contract assets

▪

Eletronuclear: No income was recognized in 2Q26 as the asset was classified as held-for-sale in 3Q25

▪

ISA Energia: The improvement in 2Q26 reflects the negative impact recorded in 2Q25 from the regulatory remeasurement arising from lower cash flows associated with the financial component of the RBSE under the transmission concession agreement extended pursuant to Law No. 12,783/2013

▪

Equatorial Maranhão: Variation resulting from the recognition of equity income from 2Q25 and 3Q25

▪

IE Madeira: No income was recognized in 2Q26 as the asset was classified as held-for-sale

Table 25 - Equity holdings (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Highlights Affiliates (a)	284	-45	n.m.	319	-11.0	603	412	46.3
Equatorial Maranhão	90	0	n.m.	139	-35.3	228	228	0.0
ISA Energia	141	25	472.0	132	7.1	273	159	71.2
Eletronuclear (1)	0	-147	n.m.	0	0.0	0	-84	n.m.
Other Affiliates	53	78	-31.4	49	9.4	102	108	-6.1
Highlights SPEs (b) (2)	64	-148	n.m.	237	-73.1	301	-101	n.m.
Central Eólica	0	0	0.0	67	n.m.	67	0	0.0
IE Madeira	0	31	n.m.	66	n.m.	66	115	-43.0
Belo Monte Transmissora de Energia S.A. - BMTE	55	27	105.1	66	-16.1	121	83	46.6
Chapecoense	47	55	-15.7	54	-14.2	101	98	2.9
ESBR Jirau	43	22	98.4	53	-17.8	96	61	57.3
Transnorte Energia (TNE)	55	-128	n.m.	46	19.5	100	-77	n.m.
IE Garanhuns	22	23	-4.7	19	19.8	41	38	7.5
Norte Energia	-158	-179	-11.5	-133	19.2	-291	-419	-30.5
Other Holdings (c) (3)	25	67	-62.0	108	-76.6	134	111	20.6
Total Equity Holdings (a) + (b) + (c)	373	-126	n.m.	664	-43.9	1,037	422	145.6
Non-recurring events
(-) Regulatory remeasurements, ISA Energia	0	116	n.m.	0	0.0	0	116	n.m.
Adjusted Equity Holding	373	-10	n.m.	664	-43.9	1,037	539	92.6

(1) 1Q26 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.

9.6. Financial Result - IFRS

Table 26 - Financial result (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Financial Income	961	1,069	-10.0	1,170	-17.8	2,131	2,142	-0.5
Interest income, fines, commissions and fees	-2	-13	-82.0	0	n.m.	-2	23	n.m.
Income from financial investments	995	1,101	-9.7	1,056	-5.8	2,051	2,159	-5.0
Late payment surcharge on electricity	69	36	93.2	27	n.m.	96	68	41.4
Other financial income	-36	24	n.m.	159	n.m.	123	53	n.m.
(-) Taxes on financial income	-64	-79	-19.1	-73	-11.6	-137	-162	-15.4
Financial Expenses	-2,298	-2,380	-3.4	-2,276	1.0	-4,573	-4,844	-5.6
Debt Charges (1)	-1,452	-1,528	-5.0	-1,403	3.5	-2,855	-3,168	-9.9
Loans, financing and suppliers	-1,441	-1,459	-1.2	-1,396	3.2	-2,837	-2,962	-4.2
Leasing	-11	-70	-83.9	-7	57.7	-18	-206	-91.1
CDE obligation charges (2)	-694	-661	4.9	-701	-1.0	-1,395	-1,323	5.4
River basin revitalization charges (2)	-72	-79	-8.1	-74	-2.9	-146	-157	-6.9
Financial discount for early payment - ENBpar	0	0	0.0	0	0.0	0	0	0.0
Other financial expenses	-80	-111	-28.6	-97	-18.4	-177	-195	-9.5
Net Financial Items	-2,188	-1,244	75.9	-2,021	8.2	-4,209	-3,347	25.7
Monetary changes	-343	-264	30.1	-311	10.4	-654	-548	19.2
Compulsory Loan	-151	-178	-14.9	-148	2.5	-299	-353	-15.3
Others	-192	-86	n.m.	-163	17.6	-355	-196	81.3
Exchange rate variations	2	-12	n.m.	17	-85.3	19	-7	n.m.
Change in fair value of hedged debt net of derivative (1)	-1,105	-587	88.3	-973	13.6	-2,079	-1,554	33.8
Monetary updates - CDE (2)	-650	-316	n.m.	-666	-2.4	-1,316	-1,048	25.5
Monetary updates - river basins (2)	-91	-52	75.7	-88	4.2	-179	-165	8.2
Change in derivative financial instrument not linked to debt protection	0	-14	n.m.	0	0.0	0	-24	n.m.
Financial Results	-3,524	-2,555	37.9	-3,127	12.7	-6,651	-6,049	10.0
*Adjustments*
Monetary restatement - Compulsory Loan	151	178	-14.9	148	2.5	299	353	-15.3
Adjusted Financial Result	-3,373	-2,377	41.9	-3,079	9.5	-6,452	-5,696	13.3

(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: R$ 961 million in 2Q26 compared to R$ 1,069 million in 2Q25, down 10%, due to decreases in average cash balances and the CDI rate during the period

▪

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

◦

R$ 1,452 million from debt charges

◦

R$ 1,105 million from the change in fair value of hedged debt, net of derivatives

These lines totaled R$ 2,558 million in 2Q26 compared to R$ 2,116 million in 2Q25. This 21% increase was mainly driven by:

•

Increase in the outstanding debt balance

•

Impact of CDI indexation

•

Adjustment to the carrying amount of the Bonds

It is also worth noting the reduction in leasing charges stemming from the sale of TPPs during the period.

▪

Monetary restatement: R$ 343 million expense in 2Q26, up 30% from R$ 264 million in 2Q25. This line comprises two main components:

◦

Monetary restatement excluding amounts related to compulsory loan proceedings: R$ 192 million expense in 2Q26 compared to the R$ 86 million expense in 2Q25, mainly due to higher inflation adjustments on debt, reflecting the increase in the Brazilian CPI (IPCA) from 0.93% in 2Q25 to 1.42% in 2Q26

◦

Monetary restatement related to compulsory loans proceedings: R$ 151 million expense in 2Q26, down from R$ 178 million in 2Q25, reflecting the reduction in provision inventory

9.7. Current and Deferred Taxes - IFRS

Recurring expenses for income tax and social contribution improved R$ 79 million, down from R$ 173 million in 2Q25 to R$ 94 million in 2Q26. This change was explained by lower deferred tax recognition, partially offset by lower current tax payments. The latter mainly reflected a lower taxable base at AXIA Energia Norte, following the write-off of the ECL provision on the assignment of Amazonas Energia credits in the quarter.

Non-recurring effects: -R$ 116 million, related to the tax on non-recurring items adjusted on EBT.

Table 27 - Income tax and social contribution (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Current income tax and social contribution	104	-254	n.m.	-561	n.m.	-458	-333	37.5
Deferred income tax and social contribution	-82	1,356	n.m.	123	n.m.	42	1,370	-97.0
Income tax and social contribution total	22	1,102	-98.0	-438	n.m.	-416	1,037	n.m.
Adjustments
Constitution/Reversal of Deferred Tax on Tax Loss	0	0	0.0	0	0	0	0	0
Deferred Tax Adjustment on Provision Reversal	0	0	0.00	0	0.00	0	0	0.00
Tax on non-recurrent items adjusted on EBT	-116	0	0.00	-63	83.89	-179	0	0.00
Adjusted income tax and social contribution	-94	-173	-45.8	-501	-81.3	-595	-238	n.m.
Adjusted Current income tax and social contribution	-12	-254	-95.19	-624	-98.05	-637	-333	91.25
Adjusted Deferred income tax and social contribution	-82	80	n.m.	123	n.m.	42	95	-56.1

(1) 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 the 2025-26, 2026-27 and 2027-28 cycles, 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 .

(2) The R$396 million recorded in 2Q25 stems from the revision of AXIA Energia Norte's deferred tax assets and liabilities, following the adoption of a new corporate income tax (IRPJ) rate of 6.25%. This lower rate applied following the divestment of its thermal power plants in May 2025, after which the company began operating exclusively with incentivized assets.

10. OPERATIONAL PERFORMANCE

10.1. Generation Segment

Generation Assets

The Company had 81 power plants, including 47 hydroelectric, 33 wind, and 1 solar at the end of 2Q26, considering corporate ventures, shared ownership and stakes via SPEs.

Portfolio installed capacity reached 44,430 MW in 2Q26, with 100% generated from clean sources with low greenhouse gas emissions, representing 17% of Brazil's total installed capacity.

Table 28 - Generation assets

Source	Installed Capacity (MW)	Assured Capacity (aMW)	Accumulated Generated Energy (GWh)
Hydro (47 plants)	43,537	21,208	84,626
Wind Power (33 plants)	892	340	797
Solar (1 plant)	0.93	0.13	0.56
Total (81 plants)	44,430	21,548	85,424

Total energy generated by AXIA Energia fell by 6.2% YoY in 2Q26.

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

System Data – Installed Capacity and Generation

Brazil's installed capacity was 268,744.56 MW in 2Q26.

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 06/30/2026 from the National Operator of the Electric System (ONS)

System Data – Energy Market

Table 29 - PLD

		2Q26	2Q25	∆%	1Q26	∆%
Market	GSF (%)	99.16	95.64	3.5 p.p.	91.53	7.6 p.p.
	PLD SE (R$/MWh)	206.57	216.45	-4.6	308.14	-33.0
	PLD S (R$/MWh)	230.82	224.26	2.9	357.96	-35.5
	PLD NE (R$/MWh)	163.50	154.07	6.1	286.79	-43.0
	PLD N (R$/MWh)	165.18	154.59	6.8	287.31	-42.5

Chart 8 - GSF (%)

Month	2021	2022	2023	2024	2025	2026
June	70%	83%	80%	89%	88%	95%

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

ENA conditions deteriorated in 2Q26, ending the quarter at 81% of SIN’s long-term average.

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

The SIN ended 2Q26 with stored energy at 71%, representing a sequential improvement.

10.2. Transmission Segment

The Company ended 2Q26 with 74.8 thousand km of transmission lines, compared to 73.8 thousand km in 2Q25, as well as 420 substations, of which 301 were Company-owned and 119 were operated by third parties.

Table 30 - Transmission lines (km)

Company	Own(1)	In Partnership (2)	Total
AXIA Energia Nordeste	22,251	1,831	24,083
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	67,550	7,278	74,829

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

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

10.3. ESG

Table 31 - ESG KPIs 2Q26

Pillar	KPI	2Q26	2Q25	Change
Planet	Accumulated GHG Emissions for the year (1)	242,709	885,107	-73%
Planet	(Scopes 1, 2 and 3) (tCO2e)	242,709	885,107	-73%
People	Accident Frequency Rate - own Employees (with time off)	0.75	0.48	56%
	Women in the Workforce (%)	21%	20%	1 p.p.
	Leadership positions held by women (%)	25%	25%	0 p.p.
Governance	Complaints answered on time (%)	92.0%	100.0%	-8 p.p.

The values presented are preliminary and unaudited, 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.

11. APPENDIX

11.1. 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 (O&M), representing remuneration for energy sold under the quota regime

Table 32 - Generation operating revenue (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Power supply to non-end consumers	3,609	4,374	-17.5	3,788	-4.7	7,397	9,717	-23.9
Power supply to end consumers	904	433	n.m.	755	19.7	1,658	928	78.8
CCEE	2,311	1,534	50.6	4,611	-49.9	6,922	2,146	n.m.
O&M revenue	283	509	-44.5	274	3.2	557	1,029	-45.9
Generation Revenues	7,106	6,851	3.7	9,428	-24.6	16,533	13,819	19.6
*Non-recurring items - Adjustments*	0	109	n.m.	0	0.0	0	109	n.m.
Adjusted Generation Revenue	7,106	6,960	2.1	9,428	-24.6	16,533	13,928	18.7

Transmission revenue comprises:

▪

Operation and maintenance (O&M) revenue, related to asset operation and maintenance

▪

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 33 - Transmission operating revenue (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
Revenue from Operation & Maintenance (O&M)	1,876	2,065	-9.2	1,995	-6.0	3,871	4,081	-5.1
Construction Revenue	1,377	1,063	29.6	1,135	21.3	2,513	1,809	38.9
Contractual Revenue - Transmission	2,403	1,951	23.2	1,884	27.5	4,287	4,374	-2.0
Transmission Revenues	5,657	5,079	11.4	5,015	12.8	10,671	10,264	4.0
*Non-recurring items - Adjustments*	0	0	0.0	0	0.0	0	0	0.0
Adjusted Transmission Revenue	5,657	5,079	11.4	5,015	12.8	10,671	10,264	4.0

11.2. Appendix 2 - PMSO Breakdown

Table 34 - PMSO 2Q26 (R$ mn)

PMSO	2Q26
(R$ million)	AXIA Energia Holding	AXIA Energia Nordeste	AXIA Energia Norte	AXIA Energia Sul	Total	Elimination	Consolidated IFRS
Personnel	365	208	163	76	811	0	811
Voluntary Dismissal Plan (PDV) - Provision	6	0	2	0	8	0	8
Material	20	8	21	5	55	0	55
Services	300	111	100	46	556	0	556
Other	110	11	36	3	160	-12	148
PMSO	801	337	321	131	1,591	-12	1,578
*Non-recurring events*
Personnel: VDP	-6	0	-2	0	-8	0	-8
Personnel: Termination Costs	-15	-16	-20	-6	-57	0	-57
Services: Success fee related to legal consulting	-34	-4	-3	-1	-42	0	-42
Adjusted PMSO	747	317	296	123	1,483	-12	1,471

Table 35 - PMSO 2Q25 (R$ mn)

PMSO	2Q25
(R$ million)	AXIA Energia Holding	AXIA Energia Nordeste	AXIA Energia Norte	AXIA Energia Sul	Total	Elimination	Consolidated IFRS
Personnel	352	220	192	85	848	51	899
Voluntary Dismissal Plan (PDV) - Provision	76	4	15	3	98	0	98
Material	12	8	16	2	37	5	42
Services	181	95	101	35	412	44	456
Other	33	27	70	6	137	28	164
PMSO	653	353	394	131	1,531	128	1,659
*Non-recurring events*
Personnel: PDV, PDC	-76	-4	-15	-3	-98	0	-98
Personnel: Termination Costs	-63	-21	-23	-9	-115	0	-115
Services: Success fee related to legal consulting	-11	-2	-2	0	-15	0	-15
Adjusted PMSO	503	326	354	119	1,303	128	1,431

Table 36 - Other costs and expenses (R$ mn)

	2Q26	2Q25	%	1Q26	%	6M26	6M25	%
GSF	52	17	n.m.	53	-2.0	105	33	n.m.
Convictions, losses and legal costs	-3	5	n.m.	49	n.m.	45	76	-40.3
Taxes	37	17	n.m.	38	-1.7	75	62	21.5
Insurance	28	24	17.2	32	-12.3	61	47	29.0
Rent	2	19	-87.4	26	-90.8	28	41	-32.7
Donations and contributions	7	29	-75.4	9	-19.2	16	50	-68.3
Equity Holding	0	18	n.m.	0	0.0	0	28	n.m.
Recovery of expenses	-15	-12	19.6	-8	92.4	-22	-24	-9.1
Others	39	48	-19.2	28	38.9	67	88	-24.3
Total	148	164	-10.3	227	-34.9	374	401	-6.7

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

Chart 11 - Receivables (R$ million)

Does not include ECL of R$ 14.5 million and current liabilities of R$ 0.5 million.

The figures presented already reflect the assignment of all receivables due from Amazonas Energia S.A., as disclosed in the Material Fact published on June 10, 2026.

11.4. Appendix 4 - Periodic Review of the 2026 RAP for Tendered Concession Agreements

ANEEL Ruling No. 2,163/2026, published on June 17, 2026, set the outcome of the Periodic Tariff Review (RTP) for the Transmission Concession Agreements included in the 2026 review cycle, establishing the resulting Allowed Annual Revenue (RAP). The review followed Call for Contributions (Tomada de Subsídios) No. 006/2026.

Fourteen tendered concession contracts held by AXIA Energia had their RAP revised in 2026.

The RAP review resulted in a positive repositioning index¹ of 6.4%, equivalent to a RAP increase of R$ 20.9 million for the AXIA Energia companies. Excluding accumulated inflation for the period, the repositioning index was a positive 2.3%, equivalent to a RAP increase of R$ 7.8 million.

The main impact came from the Reinforcements and Improvements (R&I) RAP, which rose by R$ 23.4 million, with 98.5% related to large-scale works with pre-authorized revenue. Conversely, the repositioning of the Auction Bid RAP (RAP Ofertada do Leilão) had a negative impact of R$ 2.5 million, driven by the lower cost of debt (Kd).

It is worth noting that the outcome includes Other Revenues captured by the regulator for tariff affordability purposes, with a negative impact of R$ 116 million on RAP.

In addition, the review set a total Adjustment Portion (PA) of R$ 3.0 million, at June 2026 price levels, broken down as:

▪

PA Retroactive, with a positive value of R$ 3.4 million, to be received in the next five tariff cycles

▪

PA Other Adjustments, with a negative value of R$ 488,000, to be returned by the transmission companies in the 2026/2027 cycle

The tables below break down the 2026 RTP results for the AXIA Energia companies, by concessionaire and by concession contract.

Table 37 - Total RAP: Results by concession contract (R$ million)

AXIA Energia Company	Concession Contract	Current RAP (Reference jun/25) (1)	Reviewed RAP (Reference jun/26) (2)	Impact (1) - (2)	Revenue Repositioning Index (IRR)
AXIA Energia Nordeste	004/2010	54.3	56.8	2.5	4.7
AXIA Energia Nordeste	007/2010	16.9	16.9	-0.1	-0.4
AXIA Energia Nordeste	013/2010	16.5	16.9	0.4	2.4
AXIA Energia Nordeste	014/2010	9.6	10.8	1.2	12.2
AXIA Energia Nordeste	019/2010	33.6	36.0	2.4	7.0
AXIA Energia Nordeste	020/2010	14.7	16.8	2.1	14.0
AXIA Energia Nordeste	021/2010	12.0	12.2	0.2	1.6
AXIA Energia Holding	006/2010	12.8	12.7	-0.1	-0.4
AXIA Energia Norte	009/2010	8.4	8.4	0.0	-0.3
AXIA Energia Norte	004/2011	10.0	10.5	0.5	4.7
AXIA Energia Sul	010/2005	85.5	93.6	8.1	9.4
AXIA Energia Sul	011/2010	31.7	33.1	1.4	4.4
AXIA Energia Sul	012/2010	5.9	5.8	-0.1	-0.9
AXIA Energia Sul	002/2011	15.3	17.7	2.4	16.0
Total		327.3	348.2	20.9	6.4

1 In Brazilian Portuguese, the revenue repositioning index is Índice de Reposicionamento da Receita, which ANEEL abbreviates as IRR.

Table 38 - Auctioned RAP: Results by concession contract (R$ million)

AXIA Energia Company	Concession Contract	Current RAP (Reference jun/25) (1)	Reviewed RAP (Reference jun/26) (2)	Impact (1) - (2)	Revenue Repositioning Index (IRR)
AXIA Energia Nordeste	004/2010	49.7	49.5	-0.2	-0.4
AXIA Energia Nordeste	007/2010	16.9	16.9	-0.1	-0.4
AXIA Energia Nordeste	013/2010	12.5	12.2	-0.3	-2.5
AXIA Energia Nordeste	014/2010	2.3	2.2	-0.1	-2.6
AXIA Energia Nordeste	019/2010	24.4	23.8	-0.5	-2.1
AXIA Energia Nordeste	020/2010	9.9	9.7	-0.2	-1.7
AXIA Energia Nordeste	021/2010	11.2	11.0	-0.2	-1.6
AXIA Energia Holding	006/2010	12.8	12.7	-0.1	-0.4
AXIA Energia Norte	009/2010	8.4	8.4	0.0	-0.3
AXIA Energia Norte	004/2011	4.4	4.3	-0.1	-2.8
AXIA Energia Sul	011/2010	19.6	19.1	-0.5	-2.6
AXIA Energia Sul	012/2010	5.3	5.2	-0.1	-2.5
AXIA Energia Sul	002/2011	4.3	4.2	-0.1	-2.8
Total		181.7	179.3	-2	-1.4

Table 39 - Reinforcement and Improvement RAP: Results by concession contract (R$ million)

AXIA Energia Company	Concession Contract	Current RAP (Reference jun/25) (1)	Reviewed RAP (Reference jun/26) (2)	Impact (1) - (2)	Revenue Repositioning Index (IRR)
AXIA Energia Nordeste	004/2010	4.6	7.3	2.7	60.4
AXIA Energia Nordeste	013/2010	3.9	4.7	0.7	18.0
AXIA Energia Nordeste	014/2010	7.4	8.6	1.2	16.9
AXIA Energia Nordeste	019/2010	9.3	12.2	2.9	31.2
AXIA Energia Nordeste	020/2010	4.8	7.1	2.2	46.2
AXIA Energia Nordeste	021/2010	0.8	1.2	0.4	43.5
AXIA Energia Norte	004/2011	5.6	6.2	0.6	10.6
AXIA Energia Sul	010/2005	85.5	93.6	8.1	9.4
AXIA Energia Sul	011/2010	12.1	14.0	1.9	15.7
AXIA Energia Sul	012/2010	0.6	0.7	0.1	13.2
AXIA Energia Sul	002/2011	11.0	13.5	2.6	23.3
Total		145.6	168.9	23	16.1

Table 40 - Total PA: Results by concession contract (R$ thousand)

AXIA Energia Company	Concession Contract	PA Retroactive (Reference jun/26) (1)	PA Other Adjustments (Reference jun/26) (2)	Total PA (Reference jun/26) (1) + (2)
AXIA Energia Nordeste	004/2010	1,263.9	1.3	1,265.2
AXIA Energia Nordeste	007/2010	0.0	-0.1	-0.1
AXIA Energia Nordeste	013/2010	45.3	-3.8	41.5
AXIA Energia Nordeste	014/2010	0.0	-0.7	-0.7
AXIA Energia Nordeste	019/2010	198.6	-456.6	-258.0
AXIA Energia Nordeste	020/2010	-28.3	-2.7	-31.0
AXIA Energia Nordeste	021/2010	372.5	-2.8	369.7
AXIA Energia Holding	006/2010	0.0	0.0	0.0
AXIA Energia Norte	009/2010	0.0	0.0	0.0
AXIA Energia Norte	004/2011	260.9	-1.3	259.6
AXIA Energia Sul	010/2005	46.9	-13.1	33.8
AXIA Energia Sul	011/2010	78.6	-5.8	72.8
AXIA Energia Sul	012/2010	46.9	-1.7	45.3
AXIA Energia Sul	002/2011	1,161.2	-1.4	1,159.8
Total		3,446.6	-488.8	2,957.8

11.5. Appendix 5 - RAP Annual Adjustment, 2026/2027 Cycle

ANEEL Ruling No. 2,268/2026, published on June 24, 2026, set the RAP Annual Adjustment for the transmission concession contracts, applicable to the 2026/2027 tariff cycle.

The annual adjustment resulted in a 6.7% increase in approved RAP compared with the previous 2025/2026 cycle. This increase was primarily driven by monetary restatement based on the IPCA and IGP-M inflation indices, as well as additional RAP from projects that entered commercial operation during the cycle, including recently auctioned concessions and reinforcement and improvement projects. On a combined RAP and PA basis, the increase was 8.7% compared with the amounts approved for the 2025/2026 cycle.

Table 41 - Approved RAP and PA, Annual Adjustement, 2026-2027 cycle (R$ million)

AXIA Energia Company	RAP + PA, Cycle 25/26 (Reference jun/25)	RAP + PA, Cycle 26/27 (Reference jun/26)	Change (R$ million)	Change (%)
AXIA Energia Holding	6,709	7,178	470	7.0
AXIA Energia Nordeste	4,387	5,039	652	14.9
AXIA Energia Norte	3,060	3,196	136	4.4
AXIA Energia Sul	1,808	1,927	118	6.5
NERA Caladinho	0	15	15	0.0
TMT	56	59	3	4.7
VSB	51	54	3	5.4
Total	16,071	17,467	1,396	8.7

Table 42 - Approved RAP, Annual Adjustement, 2026-2027 cycle (R$ million)

AXIA Energia Company	RAP Cycle 25/26 (Reference jun/25)	RAP Cycle 26/27 (Reference jun/26)	Change (R$ million)	Change (%)
AXIA Energia Holding	6,778	7,310	532	7.9
AXIA Energia Nordeste	4,845	5,097	251	5.2
AXIA Energia Norte	2,970	3,139	169	5.7
AXIA Energia Sul	1,834	1,961	127	6.9
NERA Caladinho	0	15	15	0.0
TMT	58	60	3	4.7
VSB	53	56	3	4.7
Total	16,538	17,638	1,100	6.7

Table 43 - Approved PA, Annual Adjustement, 2026-2027 cycle (R$ million)

AXIA Energia Company	PA Cycle 25/26 (Reference jun/25)	PA Cycle 26/27 (Reference jun/26)	Change (R$ million)	Change (%)
AXIA Energia Holding	-69	-132	-63	90.4
AXIA Energia Nordeste	-458	-57	401	-87.5
AXIA Energia Norte	90	57	-33	-36.5
AXIA Energia Sul	-25	-35	-9	35.9
NERA Caladinho	0	-1	-1	0.0
TMT	-1	-2	0	7.4
VSB	-2	-2	0	-12.7
Total	-467	-171	296	-63.4

Chart 12 - Annual Readjustment of transmission revenue, RAP and PA, 2026/2027 cycle

Chart 13 - Annual Readjustment of transmission revenue, 2026/2027 cycle

▪

IPCA/IGP-M: monetary restatement for the 2026/2027 cycle based on the IPCA of 4.72% for extended concession contracts and most tendered ones, or the IGP-M of 1.92% for certain tendered contracts.

▪

New Auction Projects: Additional RAP associated with the Nova Era Caladinho auctioned project, for which the ONS issued a Revenue Release Term (TLR) during the 2025/2026 cycle.

▪

New R&I Projects: Additional RAP associated with reinforcement and improvement projects that entered commercial operation during the 2025/2026 cycle.

▪

RTP 2026 Tendered (real gains): Result of the RTP 2026 tendered concession contracts (as per Appendix 4 - Periodic Review of the 2026 RAP for Tendered Concession Agreements).

▪

O&M Transferred Facilities: Additional RAP relating to the O&M of transmission facilities transferred during the 2025-2026 cycle.

▪

PIS and COFINS Removal: Effects of ANEEL Ruling No. 1,787/2026 associated with the removal of PIS and COFINS taxes from RAP for some contracts, due to the Tax Reform.

▪

Deactivated RAP: Reduction in RAP related to the deactivation of transmission facilities that occurred during the 2025-2026 cycle.

▪

AO&M Trajectory: Reduction of AO&M RAP (PRT 579/2012) due to the Efficient Operational Cost Trajectory, defined within the scope of RTP 2023 for extended concession contracts, which will be in effect until the 2027-2028 cycle.

▪

"Step Down Profile" of Tendered Contracts: Reduction of RAP due to the "step down profile" of tendered contracts that foresee a reduction in RAP starting from the 16th year of commercial operation.

▪

PA: as detailed in Table 43 - Approved PA, Annual Adjustment, Cycle 2026/2027 (R$ million).

In addition, projects scheduled to enter commercial operation by June 2027, ahead of the next tariff cycle, are expected to add R$ 757 million to AXIA Energia's RAP at June 2026 prices, of which R$ 263 million relates to auction projects and R$ 493 million to authorized large-scale reinforcement and improvement projects.

11.6. Appendix 6 - RAP Annual Adjustment - Adjustment Portion (PA), 2026/2027 Cycle

The Adjustment Portion (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. The resulting balance is offset in 12 equal monthly installments during the current cycle, and may be positive or negative depending on each contract's balance.

The PA established for the 2026/2027 cycle is broken down as follows:

Table 44 - Approved PA breakdown - Annual Adjusment, 2026-2027 cycle (R$ million)

PA Category	2025/2026 Cycle (Reference jun/25)	2026/2027 Cycle (Reference jun/26)
PA Measurement	-980	-684
PA Review - CC Extended	391	391
PA Review - CC Tendered	17	16
PA Financial Improvements	136	143
PA Authorizations without previous RAP	6	3
PA Other Adjustments	-18	-39
PA DIT Quality	-1	0
Total	-449	-171

The table below summarizes the key amounts established:

Table 45 - Main values from the Approved PA breakdown - Annual Adjusment, 2026-2027 cycle (R$ million)

PA Category	Description	2026/2027 Cycle (jun/26 base)
PA Measurement	It includes mainly (a) refund of amounts collected through credit notices (AVCs) related to Prepayment Apportionment, (b) refund of amounts collected related to sector charges to CDE Fund , and (c) adjustments arising from the tariff mismatch in revenues from the Basic Border Network and Other Transmission Facilities.	-684
PA Review	PA related to the retroactive effects of the RAP Reviewed for authorized Reinforcements and Improvements (R&I), covering both Extended and Tendered contracts. For Extented contracts, the PA will be offset in equal installments through the subsequent review in July 2028, whereas for Tendered contracts it will be offset over the tariff review cycle (four or five years, depending on the concession).	407
PA Financial Improvements	PA associated with the annuity for investments in small-scale improvements for the Extended concession contracts, as defined in the 2023 Tariff Review (RTP 2023). The PA is valid through the July 2028 review.	143
PA Authorization without previous RAP	PA related to the RAP's retroactive amounts for Small-Scale Reinforcements without pre-authorized revenue, with revenue defined within the scope of the RAP Annual Adjustment.	3
PA Other Adjustments Refund of Collected Termination Charges	Complementary AVCs from the termination of CUST agreements (36 EUST) with PIS/COFINS (pass-through). It is worth highlighting the context that shaped its definition. In recent years, there was a sharp increase in CUST decontracting and terminations driven by the so-called "Gold Rush" — the high number of grant (outorga) applications filed by generators through March 2022 in an effort to preserve the subsidies in transmission and distribution tariffs, after legislation set a phased termination of these discounts. However, as many projects did not materialize within their contractual deadlines, there was a high level of default on Termination Charges. Transmission companies are responsible for collecting these charges through a complementary AVC issued by the ONS and refunding them through the PA, functioning as a pass-through billed within revenue. Normative Resolution (ReN) No. 1,125/2025 established the methodology for verifying the transmission companies' best efforts in collecting the amounts related to CUST termination charges that are not effectively paid by the developers. AXIA Energia companies successfully demonstrated 100% of the Best Effort to the regulator. Accordingly, on June 2, 2026, at its 11th Ordinary Meeting, ANEEL's Board decided not to deduct, in the form of a PA in this 2026/2027 cycle, the amounts billed and charged but not received.	-1
PA Other Adjustments Ruling Nº 476/2026	First of two installments, associated with the allocation to tariff affordability of additional amounts received between 2018/2019 and 2022/2023, in compliance with Ruling No. 476/2026.	-76
PA Other Adjustments Others	This includes (a) effects from the replacement, decommissioning, or transfer of facilities, (b) compensation for the reduction in MUST, and (c) other less material events.	38
Total		-171

11.7. Appendix 7 - Transmission System Usage Tariff, 2026/2027 Cycle

ANEEL Ruling No. 2,269/2026, published on June 22, 2026, set the update to the Transmission System Usage Tariff (TUST) for the 2026/2027 cycle. The TUST is charged to transmission system users and is intended to remunerate the concessionaires for the infrastructure made available for use.

AXIA Energia holds a 100% interest in 53 generation plants connected to the Basic Grid of the National Interconnected System (SIN). Connected users remunerate the system through the Transmission System Usage Charge (EUST), calculated from the TUST and the plant's contracted capacity, under the applicable Transmission System Usage Agreement (CUST).

The update to the Basic Grid TUST for the 2026/2027 cycle resulted in a positive repositioning of the total charges payable by the sample of 53 AXIA Energia plants, representing a 9.5% increase or R$ 423 million when compared with the 2025/2026 cycle. The average tariff calculated for the 2026/2027 cycle is R$ 12.16/kW.

The change was mainly explained by the R$ 3,865 million increase in RAP of SIN transmission companies attributable to the Basic Grid, up 9.1% in the period. In addition, contracted generation capacity base fell by 3 GW, or 1.7% in the period.

It is also worth noting that some plants have stabilized tariffs under Normative Resolutions No. 267/2007 and No. 559/2013, resulting in an annual repositioning that captures inflation only. The adjustment is calculated using the Transmission Adjustment Index (IAT), which was a positive 4.45% in the 2026/2027 cycle, compared with 5.51% in the 2025/2026 cycle. AXIA Energia currently has 19 plants with stabilized tariffs.

Table 46 - Main contributions to the Transmission System Usage Charge (EUST), 2026/2027 Cycle

Indicator	2025/2026 Cycle (Reference jun/25)	Ciclo 2026/2027 (Reference jun/26)	Change (%)
EUST associated with AXIA Energia's power plants (R$ million)	4,463	4,885	9.5
RAP of SIN transmission companies (R$ million)	42,370	46,234	9.1
Contracted generation capacity (MW)	172,630	169,727	-1.7
Transmission Adjustment Index (IAT) (%)	5.5	4.5	-19.2

Table 47 - Transmission System Usage Charge (EUST), 2026/2027 Cycle (R$ million)

AXIA Energia Company	2026/2027 Cycle (Reference jun/26)
AXIA Energia Norte	1,407
AXIA Energia Nordeste	1,300
AXIA Energia Holding	972
AXIA Energia Sul	16
SPEs	1,190
Total	4,886

11.8. Appendix 8 - Accounting Statements

Table 48 - Balance sheet (R$ thousand)

	PARENT COMPANY		CONSOLIDATED
	06/30/2026	12/31/2025	06/30/2026	12/31/2025

CURRENT ASSETS	24,442,240	21,135,398	51,751,680	52,090,586
Cash and cash equivalents	3,835,885	4,660,994	11,039,660	16,417,860
Restricted cash	825,463	622,383	932,264	660,259
Securities	6,768,450	3,894,302	15,189,665	11,133,842
Clients	1,743,507	1,530,268	5,769,590	5,575,589
Transmission contract assets	4,738,209	4,765,705	10,077,513	10,693,181
Financing, loans and debentures	6,292	10,625	6,292	10,625
Remuneration for equity holdings	1,743,164	1,533,871	316,156	470,142
Taxes and Contributions	1,770,368	1,486,283	3,473,858	2,766,765
Income tax and social contribution	0	0	0	0
Right to compensation	368,468	723,294	387,824	752,496
Warehouse	0	0	0	0
Derivative financial instruments	2,795	0	21,170	64,334
Assets held for sale	1,625,629	1,011,461	2,265,391	1,072,431
Others	1,014,010	896,212	2,272,297	2,473,062

NON-CURRENT ASSETS	40,016,387	41,365,923	87,392,500	86,792,940
Restricted cash	1,690,547	1,605,632	3,569,870	3,436,804
Equity Holdings Income	425,002	425,002	0	0
Right to compensation	0	2,176	0	2,176
Financing, loans and debentures	192,423	180,568	192,423	180,568
Clients	112,350	132,067	486,119	522,859
Securities	440,401	440,401	441,084	722,673
Taxes and Contributions	1,603,307	2,582,258	2,205,953	3,178,769
Deferred income tax and social contribution	12,313,001	11,836,824	17,840,191	17,499,833
Bonds and deposits linked	4,024,029	4,216,310	5,608,316	5,762,270
Transmission contractual assets	18,397,118	18,746,924	55,388,037	53,567,662
Derivative financial instruments	172,278	516,782	697,068	1,072,386
Others	645,931	680,979	963,439	846,940

INVESTMENTS	107,461,515	108,202,833	22,754,150	24,517,185
Equity Income	106,256,095	107,026,094	21,530,806	23,322,816
Held at fair value	1,204,220	1,175,539	1,205,262	1,175,539
Other Investments	1,200	1,200	18,082	18,830

FIXED ASSETS	7,989,766	7,897,759	39,510,607	39,659,177

INTANGIBLE	20,216,141	20,477,493	75,849,500	76,625,705

TOTAL ASSETS	200,126,049	199,079,406	277,258,437	279,685,593

	PARENT COMPANY		CONSOLIDATED
	6/30/2026	12/31/2025	6/30/2026	12/31/2025
CURRENT LIABILITIES	13,868,841	16,468,877	25,211,950	30,978,400
Loans, financing and debentures	5,639,350	7,172,085	9,344,113	13,204,167
Compulsory loans - Agreements	710,815	1,071,291	711,798	1,073,452
Compulsory loans	1,523,346	1,406,460	1,523,346	1,406,460
Suppliers	893,532	1,878,308	2,075,418	3,916,279
Taxes and Contributions	240,280	454,920	788,789	1,021,353
Income tax and social contribution	0	0	0	0
Onerous contracts	2,076	0	109,588	113,944
Shareholder remuneration	45,346	135,863	45,346	136,124
Personnel obligations	385,059	506,348	829,982	1,060,856
Reimbursement Obligations	0	0	338,382	300,694
Post-employment benefits	131	77	305,501	303,832
Provision for litigation	1,297,912	648,956	1,318,983	666,092
Sector charges	98,753	115,097	666,738	886,565
Obligations under Law 14,182/2021	1,238,782	1,044,757	4,389,505	3,738,498
RGR Returns	573,965	695,705	573,965	695,705
Leasing	59,395	36,483	111,353	72,981
Derivative financial instruments	1,092,974	1,100,992	1,683,520	1,651,632
Others	67,125	201,535	395,623	729,766
NON-CURRENT LIABILITIES	64,012,916	64,180,392	129,758,317	130,205,536
Loans, financing and debentures	36,699,188	36,918,552	61,628,489	61,091,597
Shareholder remuneration	0	0	0	0
Suppliers	0	0	12,517	0
Provision for litigation	13,568,867	14,086,402	18,471,225	19,242,041
Post-employment benefits	389,440	383,875	3,272,392	3,276,459
Obligations under Law 14,182/2021	10,984,307	11,393,664	38,569,535	40,028,165
RGR Returns	0	0	0	0
Onerous contracts	2,076	4,151	229,757	282,371
Reimbursement Obligations	0	0	76,775	0
Leasing	252,916	104,478	572,385	415,625
Concessions payable - Use of public assets	69,814	70,486	589,954	589,412
Advances for future capital increases	133,066	124,543	133,066	124,543
Derivative financial instruments	814,880	151,487	878,784	151,487
Sector charges	436,327	478,305	653,203	688,574
Taxes and Contributions	85,911	88,511	89,682	198,782
Deferred income tax and social contribution	0	0	2,858,972	2,421,481
Others	576,124	375,938	1,721,581	1,694,999
SHAREHOLDERS' EQUITY	122,244,292	118,430,137	122,288,170	118,501,657
Share capital	100,135,201	100,135,201	100,135,201	100,135,201
Share issue costs	-114,029	-108,186	-114,029	-108,186
Capital Reserves and Granted Equity Instruments	14,686,462	14,689,872	14,686,462	14,689,872
Treasury shares	-3,003,436	-3,034,806	-3,003,436	-3,034,806
Profit reserves	11,818,426	11,818,426	11,818,426	11,818,426
Proposed additional dividend	0	0	0	0
Accumulated profit	3,820,241	0	3,820,241	0
Accumulated other comprehensive income	-5,098,573	-5,070,370	-5,098,573	-5,070,370
Other comprehensive income classified as held for sale	0	0	0	0
Controlling shareholders	122,244,292	118,430,137	122,244,292	118,430,137
Non-controlling shareholders	0	0	43,878	71,520
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	200,126,049	199,079,406	277,258,437	279,685,593

Table 49 - Income statement (R$ thousand)

	PARENT COMPANY		CONSOLIDATED
	30/06/2026	30/06/2025	30/06/2026	30/06/2025
CONTINUING OPERATIONS
Net operating revenue	7,303,702	7,191,028	23,899,887	20,613,133
Operating costs	-3,568,590	-4,162,849	-10,800,873	-10,923,292
GROSS PROFIT	3,735,112	3,028,179	13,099,014	9,689,841
Operating expenses	-1,950,505	-788,941	-3,447,627	-2,403,980
Other income and expenses	-33,181	85,933	199,647	190,179
Regulatory Remeasurements - Transmission Contracts	0	-1,681,819	0	-4,385,033
OPERATING RESULT BEFORE FINANCIAL RESULT	1,751,426	643,352	9,851,034	3,091,007
FINANCIAL RESULT	-3,747,974	-3,012,628	-6,650,946	-6,048,785
Income from interest, fines, commissions and fees	-2,261	138,344	-2,261	23,432
Income from financial investments	889,365	1,193,925	2,050,839	2,158,536
Late payment surcharge on electricity	6,929	2,318	96,463	68,224
Other financial income	7,732	45,507	122,856	53,298
(–) Taxes on financial income	-68,241	-89,143	-136,687	-161,536
Financial Income	833,524	1,290,951	2,131,210	2,141,954
Debt charges	-1,791,022	-1,884,688	-2,855,312	-3,168,301
CDE obligation charges	-401,127	-380,441	-1,394,786	-1,322,857
River basin revitalization charges	-38,498	-41,802	-146,460	-157,249
Other financial expenses	-102,248	-132,642	-176,912	-195,448
Financial expenses	-2,332,895	-2,439,573	-4,573,470	-4,843,855
Monetary updates – CDE	-378,493	-301,498	-1,316,082	-1,048,360
Monetary updates – river basins	-47,070	-42,670	-179,072	-165,447
Monetary reliefs	-471,407	-369,535	-653,838	-548,448
Exchange rate variations	18,737	-9,485	19,115	-6,976
Change in fair value of hedged debt net of derivative	-1,370,370	-1,140,818	-2,078,809	-1,553,607
Change in derivative financial instrument not linked to debt protection	0	0	0	-24,046
Financial items, net	-2,248,603	-1,864,006	-4,208,686	-3,346,884
PROFIT BEFORE EQUITY HOLDINGS	-1,996,548	-2,369,276	3,200,088	-2,957,778
Equity income	5,328,517	32,631	1,037,267	241,625
OPERATING PROFIT BEFORE TAX	3,331,969	-2,336,645	4,237,355	-2,716,153
Current income tax and social contribution	0	0	-457,571	-332,852
Deferred income tax and social contribution	487,780	659,157	41,647	1,370,283
NET INCOME FOR CONTINUING OPERATIONS	3,819,749	-1,677,488	3,821,431	-1,678,722
Portion attributable to controlling	3,819,749	-1,677,488	3,819,749	-1,677,488
Portion attributable to non-controlling	0	0	1,682	-1,234
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	3,819,749	-1,677,488	3,821,431	-1,678,722
Portion attributable to controlling	3,819,749	-1,677,488	3,819,749	-1,677,488
Portion attributable to non-controlling	0	0	1,682	-1,234
EARNINGS PER SHARE
Earnings per share - basic (ON/PNC)	1.33	-0.59	1.33	-0.59
Earnings per share - diluted (ON/PNC)	1.32	-0.58	1.32	-0.58

Table 50 - Cash flow statement (R$ thousand)

	PARENT COMPANY		CONSOLIDATED
	06/30/2026	06/30/2025	06/30/2026	06/30/2025
OPERATING ACTIVITIES
Profit for the year before income tax and social contribution	3,331,969	-2,336,645	4,237,355	-2,716,153
Adjustments to reconcile profit with cash generated by operations:
Depreciation and amortization	541,886	447,787	2,485,330	2,243,600
Net exchange and monetary variations	878,233	723,188	2,129,877	1,769,231
Result of acquisitions and divestments	398,011	-97,203	886,015	105,460
Financial charges	1,816,269	974,662	3,549,442	2,466,439
Equity income	-5,328,517	-32,631	-1,037,267	-241,625
Other income and expenses	33,181	-86,115	-99,086	-190,179
Transmission revenues	-3,536,959	-3,872,041	-10,671,172	-10,264,270
Construction cost - transmission	587,931	756,978	2,613,133	1,780,935
Regulatory Remeasurements - Transmission Contracts	0	1,681,819	0	4,385,033
Operating provisions (reversals)	691,935	-50,303	801,827	259,625
Write-offs of PP&E and Intangible Assets	25,602	436	156,818	-152,745
Result of hedged debt and derivatives	1,370,370	1,140,819	2,078,809	1,577,653
Other	155,828	173,960	66,638	107,968
	-2,366,230	1,761,356	2,960,364	3,847,125
(Additions)/decreases in operating assets
Clients	-185,658	54,672	-167,503	662,011
Right to compensation	378,184	549,691	378,184	555,702
Others	-108,205	1,268,465	331,997	2,049,160
	84,321	1,872,828	542,678	3,266,873
Additions/(decreases) in operating liabilities
Suppliers	-642,853	-183,189	-1,150,908	-523,399
Advances	0	0	0	0
Personnel obligations	-93,329	-107,298	-202,914	-285,949
Sector charges	-67,072	-2,465	-281,915	117,841
Others	424,617	-34,416	-355,060	-1,035,375
	-378,637	-327,368	-1,990,797	-1,726,882
Payment of financial charges	-2,421,681	-2,181,963	-4,223,698	-3,137,666
Reversion global reserve Payment	0	0	0	0
Receipt of RAP revenue	3,914,261	3,654,516	9,466,465	9,196,807
Receipt of Financial Charges from Subsidiaries	0	0	0	0
Receipt of remuneration from investments in equity holdings	4,561,603	1,242,572	575,519	527,296
Payment of litigation	-1,170,360	-1,750,604	-1,479,628	-1,874,922
Bonds and linked deposits	78,200	-430,710	33,776	38,763
Payment of income tax and social contribution	0	-14,280	-538,794	-173,967
Supplementary pension payments	-12,872	-12,354	-173,079	-166,504
Net cash provided by operating activities of discontinued operations	0	0	0	0
Net cash provided by (used in) operating activities	5,495,173	1,477,348	9,284,760	7,080,770
FINANCING ACTIVITIES
Loans and financing obtained and debentures obtained	2,000,000	0	3,200,000	500,000
Payment of loans and financing and debentures - principal	-3,336,828	-4,350,801	-6,200,207	-6,332,830
Payment of remuneration to shareholders	-90,518	-3,989,181	-90,518	-3,996,565
Payment to dissenting shareholders - incorporation of shares	0	0	0	0
Share buybacks	0	0	0	0
Payment of CDE obligations and revitalization of basins - principal	-891,031	-841,594	-3,173,514	-2,691,384
Lease payments - principal	0	-17,223	0	-25,868
Derivatives Payment	0	0	0	0
Others	-652,564	-136,635	-1,089,407	-136,635
Net cash (used in) financing activities	-2,970,941	-9,335,434	-7,353,646	-12,683,282
INVESTMENT ACTIVITIES

	PARENT COMPANY		CONSOLIDATED
Grant of advance for future capital increase	0	0	0	0
Receipt of loans and financing	2,237	274,435	2,237	2,210
Receipt of financial charges	0	110,311	0	263
Acquisition of fixed assets	-334,080	-60,946	-1,026,360	-727,574
Acquisition of intangible assets	-108,003	-19,894	-186,017	-105,746
Restricted cash	-88,667	82,095	-142,477	96,710
Financial (withdrawals)/contributions (securities)	-2,777,650	3,497,483	-3,768,822	1,801,323
Receipt of charges (securities)	343,838	229,318	860,280	280,876
Debentures Acquisition	0	0	0	0
Transmission infrastructure - contractual asset	-714,618	-756,978	-2,934,152	-1,780,935
Capital acquisition/contribution of equity holdings	-215,749	-459,213	-719,262	-591,559
Disposal of equity holdings	800,226	189,814	800,226	2,584,072
Net cash in the incorporation of subsidiaries	0	0	0	0
Net cash in the acquisition of control of investees	-256,875	0	-194,967	0
Others	0	0	0	0
Net cash provided by investment activities of discontinued operations	0	0	0	0
Net cash provided by (used in) investing activities	-3,349,341	3,086,425	-7,309,314	1,559,641
Increase (decrease) in cash and cash equivalents	-825,109	-4,771,661	-5,378,200	-4,042,871
Cash and cash equivalents at the beginning of the period	4,660,994	16,387,945	16,417,860	26,572,522
Cash and cash equivalents at the end of the period	3,835,885	11,616,284	11,039,660	22,529,651

11.9. Appendix 9 - IFRS vs. Regulatory Reconciliation

Table 51 - Reconciliation IFRS vs. regulatory (R$ thousand)

	CVM IFRS	Regulatory	Differences	CVM IFRS	Regulatory	Differences
	06/30/2026			06/30/2025
OPERATING REVENUES
Generation
Power supply for distribution companies	7,397,018	7,397,018	0	9,716,506	9,757,199	-40,693
Power supply for end consumers	1,658,290	1,658,290	0	927,549	927,549	0
CCEE revenue (short term market)	6,921,566	6,921,566	0	2,146,052	2,146,052	0
Operation and maintenance (O&M) revenue	556,557	556,557	0	1,028,535	1,028,535	0
Transmission
Operation and maintenance revenue	3,871,207	0	3,871,207	4,080,926	0	4,080,926
Construction revenue	2,512,512	0	2,512,512	1,808,870	0	1,808,870
Contract revenue – Transmission	4,287,453	0	4,287,453	4,374,474	0	4,374,474
Transmission System Availability (Rap)	0	8,396,071	-8,396,071	0	8,910,678	-8,910,678
Other income	290,602	290,602	0	220,746	220,746	0
Deductions
(-) Sector charges	-1,318,354	-1,318,355	1	-1,364,726	-1,364,726	0
(-) ICMS	-187,540	-187,540	0	-152,694	-152,694	0
(-) PASEP e COFINS	-2,087,752	-2,087,752	0	-2,170,644	-2,170,644	0
(-) Other Deductions	-1,672	-1,672	0	-2,461	-2,461	0
Net Operating Revenue	23,899,887	21,624,784	2,275,103	20,613,133	19,300,234	1,312,899
OPERATING COSTS
Personnel, Material and Services	-1,347,843	-1,347,923	80	-1,320,172	-1,320,172	0
Energy purchased for resale	-2,526,045	-2,526,045	0	-2,867,404	-3,142,399	274,995
Charges for use of the electricity grid	-1,891,695	-1,583,930	-307,765	-1,951,072	-1,657,862	-293,210
Fuel for electricity production	-1,554	-1,554	0	-781,976	-781,976	0
Construction	-2,613,133	0	-2,613,133	-1,780,935	0	-1,780,935
Depreciation	-956,509	-1,824,238	867,729	-947,842	-1,906,946	959,104
Amortization	-1,295,980	-1,301,589	5,609	-1,126,315	-1,129,694	3,379
Operating provisions/reversals	0	0	0	0	0	0
Other costs	-168,114	-168,114	0	-147,576	-147,576	0
Operating costs	-10,800,873	-8,753,393	-2,047,480	-10,923,292	-10,086,625	-836,667
GROSS PROFIT	13,099,014	12,871,391	227,623	9,689,841	9,213,609	476,232
OPERATING EXPENSES

	CVM IFRS	Regulatory	Differences	CVM IFRS	Regulatory	Differences
Personnel, Material and Services	-1,304,482	-1,308,004	3,522	-1,422,149	-1,429,216	7,067
Voluntary Dismissal Program	-16,485	-16,485	0	-193,908	-193,908	0
Remuneration and compensation	0	0	0	0	0	0
Depreciation	-133,793	-138,757	4,964	-106,627	-106,627	0
Amortization	-99,048	-128,996	29,948	-62,816	-62,816	0
Donations and contributions	-5,407	-5,407	0	-40,086	-40,086	0
Operating provisions/reversals	-801,827	-267,476	-534,351	-259,625	86,091	-345,716
Result from asset sales	-886,015	340,958	-1,226,973	-105,460	504,251	-609,711
Other expenses	-200,570	-204,930	4,360	-213,309	-228,952	15,643
OPERATING EXPENSES	-3,447,627	-1,729,097	-1,718,530	-2,403,980	-1,471,263	-932,717
Regulatory Remeasurements - Transmission Contracts	0	0	0	-4,385,033	0	-4,385,033
OPERATING RESULT BEFORE FINANCIAL RESULT	9,651,387	11,142,294	-1,490,907	2,900,828	7,742,346	-4,841,518
FINANCIAL RESULT	-6,650,946	-7,151,416	500,470	-6,048,785	-6,283,908	235,123
PROFIT BEFORE EQUITY HOLDINGS	3,000,441	3,990,878	-990,437	-3,147,957	1,458,438	-4,606,395
Equity income	1,037,267	747,456	289,811	241,625	166,439	75,186
Other income and expenses	199,647	199,647	0	190,179	190,179	0
OPERATING PROFIT BEFORE TAX	4,237,355	4,937,982	-700,627	-2,716,153	1,815,056	-4,531,209
Current income tax and social contribution	-457,571	-457,572	1	-332,852	-332,852	0
Deferred income tax and social contribution	41,647	-55,211	96,858	1,370,283	-98,423	1,468,706
NET INCOME FOR CONTINUING OPERATIONS	3,821,431	4,425,199	-603,768	-1,678,722	1,383,781	-3,062,503
Portion attributable to controlling	3,819,749	4,423,516	-603,767	-1,677,488	1,490,693	-3,168,181
Portion attributable to controlling	1,682	1,683	-1	-1,234	-106,912	105,678
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	3,821,431	4,425,199	-603,768	-1,678,722	1,383,781	-3,062,503
Portion attributable to controlling	3,819,749	4,423,516	-603,767	-1,677,488	1,385,014	-3,062,502
Portion attributable to controlling	1,682	1,683	-1	-1,234	-1,234	0

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: August 5, 2026

AXIA Energia S.A.

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.