ENGIE Brasil Energia S.A.
For Immediate Release
Additional information:
Eduardo Sattamini
Chief Executive Officer
Pierre Leblanc
Chief Financial and Investor Relations Officer
Leonardo Depiné
IR Manager Leonardo.Depine@engie.com Tel.: +55 (48) 3221-7904/7246
Video conference
On November 6, 2025 at 11:00 a.m. (BRT), 9:00 a.m. (EST) in Portuguese with simultaneous translation into English)
to access the transmission Visit our Website
Florianópolis, Brazil, November 5, 2025. ENGIE Brasil Energia S.A. ("ENGIE" or "Company") - B3: EGIE3, ADR: EGIEY - announces earnings for the Third Quarter and nine months period ending on September 30, 2025 (3Q25/9M25). The information in this release is shown on a consolidated basis and in accordance with Brazilian accounting principles and practices. The values are expressed in Brazilian Reais (R$), except where otherwise indicated. Rounding effects may cause differences in percentage changes, when comparing the comments on Economic-Financial Performance, presented in R$ million, with the Income Statement (Appendix III), presented in R$ thousand.
hydropower plants now incorporated into ENGIE Brasil Energia's asset portfolio.
November 28
* The recording of the event will be made available the week following the event.
Net operating revenue reached R$ 3,343 million in 3Q25, 31.8% (R$ 806 million) higher than recorded in 3Q24.
Adjusted Ebitda2 in 3Q25 reached R$ 1,871 million, an increase of 12.4% (R$ 206 million) compared to the 3Q24.
The adjusted net income was R$ 731 million in 3Q25, 9.8% (R$ 65 million) higher than posted in the 3Q24.
The average price of the energy sales agreements, net of taxes on revenues and trading operations, was R$ 211.6/MWh in 3Q25, 2.0% lower than registered in the 3Q24.
Excluding trading operations, the energy sales volume in 3Q25 was 10,308 GWh (4,668 average MW), 15.3% higher than sold in 3Q24.
At the end of 3Q25, 165 of the 188 wind turbines of the Serra do Assuruá Wind Complex, in Bahia were in commercial operation and a further 23 on a test basis, corresponding to 846 MW installed and commissioned.
Four of the 16 photovoltaic parks were operating commercially and 12 on a test basis at the Assú Sol Photovoltaic Complex at end of 3Q25, equivalent to 752 MWac in operation.
For the 15th time, the Company was recognized with Anefac's Transparency Trophy, awarded to companies employing the best governance and transparency practices in their financial statements published for the market.
Summary of Financial
Consolidated (in R$ million) | 3Q25 | 3Q24 | Var. | 9M25 | 9M24 | Var. |
Net Operating Revenue (NOR) | 3,343 | 2,537 | 31.8% | 9,442 | 7,948 | 18.8% |
Results from Operations (EBIT) | 1,527 | 1,382 | 10.5% | 4,790 | 5,997 | -20.1% |
Ebitda 1 | 1,882 | 1,654 | 13.8% | 5,797 | 6,780 | -14.5% |
Adjusted Ebitda 2 | 1,871 | 1,665 | 12.4% | 5,778 | 5,432 | 6.4% |
Adjusted Ebitda by transmission and quota effects 3 | 1,763 | 1,596 | 10.5% | 5,284 | 5,141 | 2.8% |
Ebitda / NOR - (%) 1 | 56,3 | 65,2 | -8.9 p.p. | 61,4 | 85,3 | -23.9 p.p. |
Adjusted Ebitda / NOR - (%) 2 | 56,0 | 65,6 | -9.6 p.p. | 61,2 | 68,3 | -7.1 p.p. |
Net Income | 738 | 658 | 12.2% | 2,132 | 3,213 | -33.6% |
Adjusted Net Income | 731 | 666 | 9.8% | 2,119 | 2,314 | -8.4% |
Adjusted Return on Equity (ROE) 4 | 23,6 | 26,5 | -2.9 p.p. | 23,6 | 26,5 | -2.9 p.p. |
Adjusted Return on Invested Capital (ROIC) 5 | 14,9 | 16,7 | -1.9 p.p. | 14,9 | 16,7 | -1.9 p.p. |
Net Debt 6 | 24,534 | 19,095 | 28.5% | 24,534 | 19,095 | 28.5% |
Gross Power Production (avg MW) 7 | 6,167 | 6,338 | -2.7% | 5,218 | 6,194 | -15.8% |
Energy Sold (avg MW) 8 | 4,668 | 4,050 | 15.3% | 4,455 | 3,990 | 11.7% |
Average Net Sales Price (R$/MWh) 9 | 211,61 | 215,96 | -2.0% | 213,98 | 221,44 | -3.4% |
Number of Employees - Total | 1,340 | 1,234 | 8.6% | 1,340 | 1,234 | 8.6% |
EBE Employees | 1,311 | 1,211 | 8.3% | 1,311 | 1,211 | 8.3% |
Employees on Under Construction Plants | 29 | 23 | 26.1% | 29 | 23 | 26.1% |
3
Ebitda: net income + income tax and social contribution + financial result + depreciation and amortization.
Adjusted Ebitda: net income + income tax and social contribution + financial result + depreciation and amortization + impairment + non-recurrent.
Adjusted EBITDA, less the effects of IFRS in the transmission segment and quota plants.
ROE: adjusted net equity for the past 4 quarters /shareholders' equity.
Subsequent EventsROIC: effective tax rate x adjusted EBIT / invested capital (invested capital: debt
- cash and cash equivalents - deposits earmarked for debt servicing + SE).
Adjusted amount, net of gains from hedge operations.
Total gross electricity output from the plants operated by ENGIE Brasil Energia.
Disregarding sales for quota regime (Jaguara and Miranda HPPs).
Net of taxes and trading operations.
The Company has again been certified as one of the best places to work according to the GPTW - Great Place to Work Brasil ranking. This accolade reinforces ENGIE's purpose of building an increasingly healthier, inclusive and engaging environment.
The Board of Directors approved the increase in the capital stock through the issue of new common, book entry shares with no par value, distributed to the Company's shareholders in the form of bonus shares in the proportion of 1 share for every 2.5 already held.
This material contains information and opinions on future events subject to risks and uncertainties, based on current expectations, projections and tendencies. Several factors may affect the estimates and assumptions which may cause the forward-looking statements not to be realized. Therefore, shareholders and investors should not make decisions based solely on these estimates, projections and statements.
Message from ManagementThe third quarter of 2025 was characterized by the operational solidity and the market recognition, reinforcing ENGIE Brasil Energia's position as one of the leading companies in the domestic power generating sector as well as a benchmark in sustainability.
From the financial point of view, we were able to report consistent results sustained by the disciplined execution of strategy and the maturation of assets recently incorporated in the portfolio. Net operating revenue amounted to R$ 3.3 billion, a year-over-year growth of 31.8%. Adjusted Ebitda reported R$ 1.9 billion, an increase of 12.4% while adjusted net income amounted to R$ 731 million, a 9.8% improvement in relation to the third quarter 2024. These results reflect efficiency in operational management, and an increase in energy sales volume and performance in both generation and transmission segments.
In the free energy market, the Company recorded expansion of 17.6% in the customer base compared to the same period in the preceding year, evidence of growing competitiveness in long-term solutions and enhanced interest in renewable and sustainable sources. 4
Among the projects under construction, special mention should be made of progress at the Serra do Assuruá Wind Complex, ENGIE's largest wind complex worldwide and located in Gentio do Ouro (BA). The assembly and commissioning of all 188 wind turbines, totaling 846 MW of installed capacity, have been concluded with their output delivered in its entirety to the Free Contracting Environment (ACL).
Located in Assú (RN), work on the Assú Sol Photovoltaic Complex had advanced to 99.5% completion by the end of September with four of the 16 plants already in commercial operation and the remaining 12 at test phase, equivalent of 752 MWac in operation. Entry into full commercial operation is scheduled for the first quarter of 2026, making the Complex one of the largest solar operations in Brazil.
We successfully obtained the recertification of
standards attesting to the maturity of our quality, environmental and occupational safety management systems.
In addition, the Asa Branca Transmissora de Energia (BA, MG and ES) moved ahead with the issuance of the Preliminary License and filing the application for the Installation License with the Federal Environmental Protection Agency (Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis) - Ibama for one of the sectors and respective substations in addition to progress made on civil work and assembly of structures and cables. The project, with approximately 1,000 kilometers in length, is to reinforce the infrastructure for the offtake of renewable energy generated in the Northeast, contributing to the safety and integration of the Brazilian electric energy system.
ENGIE Brasil Energia was the focus of important recognition, underscoring its commitment to the ESG agenda and the generation of responsible value. We were once more certified as one of the best places to work in Brazil according to the Great Place to Work ranking as well as featuring in TIME magazine's (in partnership with Statista) among the Best Employers in Brazil - an accolade which reflects our inclusive, safe and engaging working environment.
For the 15th consecutive occasion, we were awarded the Transparency Trophy and, in 2025, the Good ESG Practices prize, both presented by ANEFAC, reaffirming our credibility and transparency in the market. We were also ranked second in the Valor 1000 Award, Energy Sector, consolidating our position of leadership and market trust in the Company's responsible actions.
Such recognition reflects solid and integrated management, supported by efficient processes and high standards of quality and governance. In this context, we obtained recertification of ISO 9001, 14001, and 45001 standards, which attest to the maturity of
our quality, environmental, and occupational safety management systems - essential pillars for ensuring operational excellence and long-term sustainability.
Reinforcing this trajectory of continuous improvement, in October, the Sustainability Officer was created and headed by Thais Soares. The new structure strengthens the integration of environmental, social, and governance pillars in all the dimensions of the business and aligns the Company with ENGIE's global model, which is increasingly oriented towards the energy transition.
We ended the quarter confident in the future and with the conviction that we are on the right track for spearheading the Brazilian energy transition, combining economic performance, innovation, and social and environmental responsibility. We thank all employees, customers, investors, and partners who contribute to building this trajectory.
Good reading!
5
Eduardo Sattamini
Chief Executive Officer
Pierre Leblanc
Chief Financial and Investor Relations Officer
Earnings Release 3Q25 ENGIE Brasil Energia S.A.
Breakdown of AssetsAt the end of the 3Q25, ENGIE Brasil Energia had 10,581.3 MW of installed capacity and operates a generating complex with 12,281.0 MW, comprised of 130 plants (13 hydro and 117 complementary energy source plants - biomass, SHP, wind powered and solar), 127 of which are wholly-owned by the Company and three (the Itá, Machadinho and Estreito Hydropower Plants) jointly-owned through consortia with other companies.
On October 1, 2025, the operation for transferring 95% of the shares of the Ibitiúva Bioenergética biomass cogenerating plant to Tereos Açúcar e Energia Brasil S.A. was concluded, the plant no longer being a component of the Company's portfolio as of this date.
Generating
Installed Capacity (MW) Authorization Commercial capacity
| Generating Complex as of September 30, 2025 6
Installed Capacity (MW) Commercial capacity Concession Power Plants Source Location Company's (aMW) Company's Total expiration date Share Share | ||||||
Itá | Hydro | Uruguai River (SC and RS) | 1,450.0 | 1,126.9 | Dec/32 | 528.7 |
Salto Santiago | Hydro | Iguaçu River (PR) | 1,420.0 | 1,420.0 | Nov/30 | 702.2 |
Machadinho | Hydro | Uruguai River (SC and RS) | 1,140.0 | 414.8 | Oct/35 | 143.7 |
Salto Osório | Hydro | Iguaçu River (PR) | 1,103.7 | 1,103.7 | Apr/31 | 487.3 |
Estreito | Hydro | Tocantins River (TO and MA) | 1,087.0 | 435.6 | Feb/47 | 244.1 |
Cana Brava | Hydro | Tocantins River (GO) | 450.0 | 450.0 | Dec/35 | 247.8 |
Jaguara | Hydro | Grande River (MG) | 424.0 | 424.0 | Jun/48 | 324.0 |
Miranda | Hydro | Araguari River (MG) | 408.0 | 408.0 | Jun/48 | 188.3 |
Santo Antônio do Jari | Hydro | Jari River (AP and PA) | 393.0 | 393.0 | Oct/45 | 211.3 |
São Salvador | Hydro | Tocantins River (TO) | 243.2 | 243.2 | Jun/40 | 140.8 |
Passo Fundo | Hydro | Passo Fundo River (RS) | 226.0 | 226.0 | Apr/31 | 107.5 |
Cachoeira Caldeirão | Hydro | Araguari River (AP) | 219.0 | 219.0 | Aug/48 | 123.3 |
Ponte de Pedra | Hydro | Correntes River (MT) | 176.1 | 176.1 | Mar/37 | 127.6 |
Total - Hydro | 8,739.9 | 7,040.2 | 3,576.6 | |||
Power Plants Source Location Company's (aMW) Company's Units1Total expiration date Share Share | |||||||
Serra do Assuruá Complex 2 | Wind Farm | 21 | Lages and Pedro Avelino (RN) | 742.5 | 742.5 | Nov/56 | 366.4 |
Assu Sol Complex 3 | Solar | 4 | Assú (RN) | 171.6 | 171.6 | Feb/57 | 52.9 |
Santo Agostinho Complex - Phase I | Wind Farm | 14 | Lages and Pedro Avelino (RN) | 434.0 | 434.0 | May/56 | 224.2 |
Campo Largo II Complex | Wind Farm | 11 | Umburanas (BA) | 361.2 | 361.2 | Aug/54 | 192.5 |
Umburanas Complex - Phase I | Wind Farm | 18 | Umburanas (BA) | 360.0 | 360.0 | Aug/49 | 213.3 |
Campo Largo I Complex | Wind Farm | 11 | Umburanas (BA) | 326.7 | 326.7 | May/51 | 166.5 |
Trairi Complex | Wind Farm | 8 | Trairi (CE) | 212.6 | 212.6 | Sep/41 | 97.2 |
Lar do Sol Complex4 | Solar | 3 | Pirapora (MG) | 198.0 | 198.0 | Sep/41 | 53.0 |
Paracatu Complex | Solar | 4 | Paracatu (MG) | 132.0 | 132.0 | Jun/51 | 34.0 |
Juazeiro Complex | Solar | 4 | Juazeiro (BA) | 120.0 | 120.0 | Jun/51 | 34.8 |
Sertão Solar Complex | Solar | 4 | Barreiras (BA) | 94.6 | 94.6 | Jul/53 | 26.1 |
Floresta Complex | Solar | 3 | Areia Branca (RN) | 86.0 | 86.0 | Jun/51 | 25.1 |
Sol do Futuro Complex | Solar | 3 | Aquiraz (CE) | 81.0 | 81.0 | Jun/51 | 16.2 |
Ferrari Termoelétrica | Biomass | Pirassununga (SP) | 72.5 | 72.5 | Jun/42 | 25.6 | |
São Pedro Complex | Solar | 2 | Bom Jesus da Lapa (BA) | 54.0 | 54.0 | Mar/51 | 16.0 |
Assú V | Solar | Assú (RN) | 34.0 | 34.0 | Jun/51 | 9.2 | |
Rondonópolis | SHP | Ribeirão Ponte de Pedra (MT) | 26.6 | 26.6 | Dec/37 | 14.0 | |
José Gelazio da Rocha | SHP | Ribeirão Ponte de Pedra (MT) | 24.4 | 24.4 | Dec/37 | 11.9 | |
Nova Aurora | Solar | Tubarão (SC) | 3.0 | 3.0 | not applicable5 | 0.2 | |
Tubarão | Wind Farm | Tubarão (SC) | 2.1 | 2.1 | not applicable5 | 0.3 | |
Tubarão 2 | Wind Farm | Tubarão (SC) | 4.2 | 4.2 | not applicable5 | 0.0 | |
Total - Complementary | 3,541.1 | 3,541.1 | 1,579.4 |
Total | 12,281.0 | 10,581.3 | 5,156.0 |
For the composition of wind and solar complexes.
Complex composed of 24 wind power plants, 21 of which in full commercial operation on 9/30/2025.
Complex composed of 16 wind power plants, 4 of which in full commercial operation on 9/30/2025.
The Lar do Sol plant does not have a declared physical guarantee, therefore its commercial capacity is based on expected generation.
For generating plants with installed capacity lower than or equal to 5 MW the legal instrument applicable is the record.
Transmission line
Location
Extention km
Annual RAP
Substations
Property
Concession
| Transmission Assets under Operation as of September 30, 2025
Gralha Azul | State of Paraná | 909.0 | (R$ million) * 341.1 | 5 own and expansion of 5 existing ones | 100% | expiration Mar/48 |
Novo Estado | States of Pará and Tocantins | 1,800.0 | 463.0 | 1 own and expansion of 3 existing ones | 100% | Mar/48 |
Gavião Real | State of Pará | - | 7.8 | New patio in 1 existing | 100% | Sep/52 |
Graúna - brownfield section | Minas Gerais and Espírito Santo | 162.0 | 14.0 | 2 existing ones | 100% | Dec/54 |
Total | 2,871.0 | 825.9 |
* RAP: Annual Allowed Revenue. / Values on the base date of June 2025 (cycle 2025-2026), net of PIS and Cofins charges.
7
Transportadora Associada de Gás S.A. - TAG.
The largest natural gas transportation operation in Brazil, TAG has an infrastructure of approximately 4,600 km of high-pressure gas pipelines extending along the country's southeastern and northeastern seaboards as well as a further section of line between Urucu and Manaus, in the state of Amazonas, crossing 10 Brazilian states and around 200 municipalities.
The gas pipeline network has several interconnection points, among them, 14 active gas entry points (including three Liquified Natural Gas (LNG)), a further 90 gas outlet points and two entry and outlet points (one more under construction), connection with 10 gas distributors, serving two refineries, ten thermoelectric power plants and two fertilizer plants. The network includes also 11 compressor stations along its length, all of them wholly owned. The operation of the assets is executed from the Control and Supervision Center (CSC) in the company's headquarters in the city of Rio de Janeiro.
TAG is 100% contracted through long-term legacy contracts with Petrobras and a connection contract to serve the Sergipe Hub in the Northeast region, all regulated by the National Petroleum, Natural Gas and Biofuels Agency (ANP). In addition to these, TAG signed 534 firm contracts in 2025 (55 active), which totaled 12.6 million m3 of transportation capacity, in entry and delivery point agreements, representing around 14% of TAG's total revenue for the year (16% considering only the integrated network).
| Corporate Structure
RR AP
ENGIE S.A.
32.5%
Solimões
Basin AM
AC
RO
PA MA CE
RN
PB
PI PE
TO AL
SE
MT BA
Sergipe Alagoas Basin
50.0% ENGIE Brasil Energia
LNG Terminal
GO
MG
MS ES
SP RJ
PR
Recôncavo Basin
Espírito Santo Basin Campos Basin
17.5%
SC Santos Basin
RS
TAG has a series of projects in hand to be executed over the next five years which are expected to surpass R$ 5.4 billion in investments. 57% of this amount will be allocated in projects to expand TAG's transportation capacity or extend the network in line with the positive outlook of ENGIE Group for the natural gas industry in Brazil.
| Completed Project:
Itagibá outlet point, in the state of Bahia, is a new delivery point to attend the local distribution company, situated along the northern leg of Gasene. This project required an investment of R$ 19.6 million. Work has been completed in August 2023 and is now awaiting the issue of the Operating Permit.
| Project under Implementation:
Buriti delivery point, in the state of Amazonas for connecting the local distribution network, will be implemented to meet thermoelectric demand in the Manaus region, bringing energy security and supporting the region's decarbonization. The project had its Construction Permit issued in July 2025. Completion is expected for the second quarter of 2026.
| Main Projects under Development:
Suape entry point, a new entry point that will allow the injection of gas from the LNG Regasification Terminal in the Port of Suape, located at Ipojuca (PE).
Miranga entry point, a new entry point for connecting Petroreconcavo's new Miranga Field Natural Gas Processing Unit (NGPU) to the TAG network at the Catu Gas Distribution Hub (GDH) in Pojuca (BA).
Itajuípe compressor station, located on the northern leg of the Gasene pipeline, for increasing current transportation capacity 8
by 3 million m3/day. The project is listed in the New Growth Acceleration Program (PAC).
Goytacazes Gas Pipeline (GASOG), connection of the Porto do Açú regasification terminal to the Cabiúnas-Vitória gas pipeline, 45 km long and 10 million m3/day of transportation capacity. The preliminary agreement for the design was approved at the end of 2022.
Storage: TAG and Origem Energia have signed a non-binding agreement for developing the first natural gas storage project in Brazil. The project's estimated total investment, when feasible, will be approximately US$ 200 million, split into different stages. On completion of the initial stage, storage capacity will be 51 million m³/year. Over the long term, capacity may reach as much as 500 million m³/year.
In addition, other projects at different phases of study could require about R$ 20 billion in investment, representing significant growth potential.
| Contracts Breakdown
Contract/Section | Extension (km) | Customer | Contract Maturity1 | Volumes Contracted (MM m³/day) | % of Net Operating Revenue2 | Readjustment index |
Gasene | 1,400 | Petrobras | Nov/33 | 30.3 | 40.1% | 46% basket IGP3; 54% US PPI |
Malha Nordeste | 2,100 | Petrobras | Dec/25 | 21.6 | 23.2% | IGP-M |
Pilar-Ipojuca | 200 | Petrobras | Nov/31 | 15.0 | 6.3% | IGP-M |
Urucu-Coari-Manaus | 800 | Petrobras | Nov/30 | 6.7 | 29.7% | 50% IGP-M; 50% IPCA |
Conexão GNL Sergipe | 25 | Eneva | Oct/54 | 14.0 | 0.5% | 20% IGP-M; 80% IPCA |
Lagoa Parda-Vitória4 | 100 | Various | Dec/25 | 0.3 | 0.2% | 55% IGP-M; 45% IPCA |
Total | ~4,600 | 87.9 | 100.0% |
1 Following the expiry of the agreements, a five-year tariff revision cycle will be triggered, which will decide the revised maximum permitted revenue flow (RAP).
2 Variations in revenue representativeness between GTAs may occur.
3 1/3 IGP-M, 1/3 IPA-DI; 1/3 IGP-DI.
4 Capacity of the section contracted under the entry and exit regime through the Capacity Offer Portal (POC) for the period from January to December 2025.
Jirau Energia - Rondônia.
Jirau Energia is responsible for the maintenance, operation and sale of energy generated by the Jirau Hydroelectric Power Plant, located on the Madeira River, in the city of Porto Velho, state of Rondônia. The Jirau Hydro Power Plant has had 50 generating units in operation since November 2016, representing a total installed capacity of 3,750 MW.
20%
40%
40%
On May 20, 2025, the Ministry of Mines and Energy (MME) issued Order 2.946, establishing the new physical guarantee amounts for Jirau HPP. The defined values are
2,222.6 average MW for operation at the 90-meter
| Jirau Energia PPA's Portfolio | Average MW
2,257 | 2,257 | 2,257 | 2,257 | 2,257 |
98 | 98 | 98 | 98 | 98 |
2,152 2,182
extended level and 2,335.1 average MW for operation at
14 93
14 94
14 42
the 90-meter constant level.
Of the total increase in firm energy, one-third belongs to the Bolivian government. As a result, the portion allocated to Brazil corresponds to 2,182.2 average MW at the 90-meter extended level and 2,257.2 average MW at the 90-meter constant level.
ENGIE Brasil Energia is awaiting a signal from its controlling company together with the Company's statutory bodies, begin studies and proposals for the transfer of the 40% stake in Jirau Energia, and 100% in the trading company Geramamoré Participações e
Comercializadora de Energia Ltda.
538
1,565
(58)
538
1,565
(29)
538
1,565
558
22 14
1,565
580
14
1,565
1,950
209
2,159
9
2025
2026-27 2028-34
2035
2036-42
2043
2044-45
In 3Q25, Jirau Energia generated 826 average MW, 113.2% higher than the 387 average MW for 3Q24, while the National Electrical System Operator Uptime Ratio
(FID) was 100% (data subject to final Electric Energy Trade Board (CCEE) booking). Out of the total generated in 3Q25, the quota attributed to Brazil was 811 average MW, discounting the quota pertaining to the Bolivian government.
Asa Branca Transmission System - Bahia, Minas Gerais and Espírito Santo.
Acquired in the Transmission Auction 01/2023, promoted by Aneel, Block 5 was named Asa Branca and will have around 1,000 kilometers of extension. Located in the states of Bahia, Minas Gerais and Espírito Santo the project provides for the implementation of four 500kV single-circuit transmission lines. The concession period for the public transmission service, including licensing, construction, operation and maintenance of the transmission facilities will be 30 years from the start of the concession agreement, as of September 27, 2023.
On June 24, 2025, the Instituto Brasileiro do Meio Ambiente - Ibama (Federal Environmental Protection Agency) issued a Preliminary License for the LT 500kV Poções III - Medeiros Neto II - João Neiva 2 - Viana 2 sections and associated substations. In 3Q25, a request for an Installation License was filed with this same federal organ.
Again, in 3Q25, work on the LT 500kV Morro do Chapéu II - Poções III proceeded apace, activities involving the assembly of equipment and commissioning work at substations as well as activities for the assembly of metallic structures for stringing cables and commissioning in the transmission line. Start-up of operations along this stretch is scheduled for 4Q25.
The maximum deadline for starting operations is March 2029.
Block
Location
Contracted RAP Estimated Aneel Capex
(R$ million)1(R$ million)
5 Bahia, Minas Gerais and
Espírito Santo
282.7 2,667.0
1 Value as of June 2025.
Total 282.7 2,667.0
BA
Asa Branca
MG
ES
10
Graúna Transmission System - Santa Catarina, Paraná, Minas Gerais, São Paulo and Espírito Santo.
Winner of the Aneel Transmission Auction 02/2024, Block 1 was denominated Graúna and contemplates the implantation of six new transmission lines, one of which is a sectioning, totaling around 732 kilometers in length, in addition to two new substations and five expansions of existing substations, in the states of Santa Catarina, Paraná, Minas Gerais and São Paulo. The scope of the project also includes the continued servicing of four existing lines (totaling 162 kilometers) and two substations in the states of Minas Gerais and Espírito Santo.
The public service transmission line concession, including licensing, construction, operation, and maintenance of the transmission installations will be 30 years from the date of signature of the concession agreement, which occurred on
MS
Gralha Azul
BA
GO
MG
Graúna ES
SP
RJ
PR
SC Graúna
Asa Branca
December 9, 2024.
In 3Q25, the project saw further advances with the negotiation of the Main Supply Contracts, and the conclusion of submission of applications for all Preliminary Licenses to the respective environmental organs. Also, important initiatives in the quarter
Transmission Assets
Greenfield Lot - Auction 02/2024 Brownfield Lot - Auction 02/2004 Power plants under operation
were land property regularizations, with the start of negotiations and approvals for construction work, progress in surveying and drilling activities, and progress in the development of executive projects.
On July 18, 2025, the Company assumed the operation of the brownfield section of the project, comprising 162 kilometers of lines and two substations, located in the states of Minas Gerais and Espírito Santo. The Annual Allowed Revenue (RAP) for this section is R$ 14.0 million, corresponding to approximately 5% of the project total.
The maximum permitted term for construction is 60 months, albeit with the possibility of abbreviating the period. The project enjoys relevant locational synergies with Gralha Azul Transmission System and other assets in the Company's portfolio, favoring operational and strategic gains.
Block
Location
Contracted RAP Estimated Aneel Capex
(R$ million)1(R$ million)
1 Santa Catarina, Paraná, Minas Gerais, São Paulo and Espírito Santo
268.3 2,933.6
1 Value as of June 2025.
Total 268.3 2,933.6
Serra do Assuruá Wind Complex - Bahia.
Comprising 24 wind farms, being installed in a single phase in the municipality of Gentio do Ouro, state of Bahia, the project's authorization grant has been issued by Aneel. The complex has an estimated installed capacity of 846 MW and an estimated commercial capacity of 410.2 average MW. Energy generated will be entirely directed to the Free Contracting Environment, the wind complex also being able to meet demand from clients in the energy self-production market. With the creation of around 3,000 direct and indirect jobs in the region, the estimated investment is approximately R$ 6 billion (as of May/2022).
Work on the construction of the complex has been completed, including the assembly and commissioning of the wind turbines,
all of them fully operational and awaiting Aneel approval for commercial operations to begin.
As of September 30, 2025, 165 wind turbines were operating commercially, while a further 23 were at a test phase, totaling 846 MW installed and commissioned.
| Commissioning
Test basis
Commercial op.
6/30/2025 9/30/2025 11/5/2025
11
188 | 188 | 188 | ||
23 | 23 | 23 | ||
(12%) | (12%) | (12%) | ||
165 | 165 | 165 | ||
(88%) | (88%) | (88%) |
Assú Sol Photovoltaic Complex - Rio Grande do Norte.
The project is located in the municipality of Assú, state of Rio Grande do Norte and is to have an installed capacity of approximately 752 MWac (895 MWp) and an estimated commercial capacity of 229.6 average MW. At an investment worth approximately R$
3.3 billion (as of Jan/23), its energy entirely fed into the Free Contracting Environment.
Implementation activities had advanced to 99.5% completion by the end of 3Q25. Component supply, earth moving activities, tracker foundations and assembly, installation of solar panels, inverters and medium voltage substations, medium and low voltage interconnections, as well as commissioning, were already concluded in the quarter, culminating in the energization of the entire photovoltaic complex. Execution of residual drainage activities as well as reliability and performance tests of some photovoltaic units were still ongoing at the end of the quarter.
The entry into operation of the first photovoltaic units on a test basis took place in October 2024. At the end of 3Q25, four of the 16 farms were already in commercial operations and 12 were in a test phase, output totaling 752 MWac in operation.
The entry into full commercial operations is scheduled for the first quarter of 2026.
| Commissioning
16 16
16
Under construction Test basis
Commercial op.
6/30/2025
9/30/2025
11/5/2025
4
(25%)
4
(25%)
4
(25%)
8
(50%)
12
(75%)
12
(75%)
4
(25%)
Projects under development are in the pipeline and at an advanced stage in the relative feasibility studies, albeit with no commitment to begin construction and awaiting adequate commercial conditions and evidence of future pricing for investments.
Plants
Source
Location
Installed Capacity (MW)
Total Company's Share
Santo Agostinho Solar Complex | Solar | Lajes and Pedro Avelino (RN) | 509.0 | 509.0 |
Campo Largo Solar Complex | Solar | Umburanas and Sento Sé (BA) | 308.0 | 308.0 |
Santo Agostinho Wind Complex - Phase II | Wind | Lajes and Pedro Avelino (RN) | 279.0 | 279.0 |
Umburanas Wind Complex - Phase II | Wind | Umburanas (BA) | 250.0 | 250.0 |
Campo Largo III Wind Complex | Wind | Umburanas and Sento Sé (BA) | 250.0 | 250.0 |
Alvorada Solar Complex | Solar | Bom Jesus da Lapa (BA) | 100.0 | 100.0 |
Total | 1,696.0 | 1,696.0 |
12
Besides the abovementioned projects, the Company is also examining opportunities in areas with high energy potential, as well as partnerships which could accelerate the development in line with the process of energy transition of ENGIE Group.
Operating Development Energy Generating Park and Transmission Lines UptimeIn 3Q25, the hydropower plants operated by ENGIE Brasil Energia achieved an uptime ratio of 96.6%, (considering programmed and forced stoppages) a year-on-year increase of 8.5 p.p., in comparison with the same quarter of 2024, when they operated at 88.1%. This variation is largely due modernization work on the Salto Santiago and Salto Osório hydropower plants in 3Q24.
Regarding the complementary plants, since 1Q25, the Company discloses its energy uptime ratio for its wind and photovoltaic complexes, a methodology which will reflect the business from a better technical point of view, given that these sources of energy rank increasingly more important relative to the Company's overall portfolio.
The energy uptime ratio in 3Q25 for the wind plants was 93.9%, 5.8 p.p. higher than 3Q24 when it reached 88.1%. The improvement in performance reflects operational stabilization at the Santo Agostinho Wind Complex, start-up in operations of which in 3Q24 was characterized by a performance below current levels in the first few months.
In relation to the photovoltaic plants, the energy uptime ratio was 93.3% in 3Q25 a growth of 4.2
p.p. in relation to the 89.1% recorded in 3Q24. This increase is related to the implementation of the Company's maintenance procedures on the photovoltaic plants acquired in 2024. Initiatives involved improvement to inverter, tracker and medium voltage network systems and optimization of solar module cleaning.
In transmission assets, Engie Brasil Energia recorded a strong operational performance at Gralha Azul, Novo Estado, Gavião Real and Graúna with a total uptime index of 100% in 3Q25, and 99.98% for the full year 2025. The transmission assets have turned in excellent operational performance since their entry into commercial
| Uptime Operating | Considering Scheduled and Forced Shutdowns
0.03 p.p.
8.5 p.p.
5.8 p.p.
4.2 p.p.
96.6%
88.1%
88.1%
93.9%
89.1%
93.3%
99.97%100.00%
operations.
Hydro
Wind
3Q24 3Q25
Photovoltaic
Transmission
3Q24 3Q25
Energy GenerationIn the third quarter of 2025, the plants operated by ENGIE Brasil Energia produced 13,617 GWh (6,167 average MW), a reduction of 2.7% compared with the same period in 2024.
Of the total generated, the hydropower plants contributed with 10,071 GWh (4,561 average MW), while the complementary sources generated 3,547 GWh (1,606 average MW). These results represent a drop of 11.1% in hydropower generation and an increase of 33.1% in energy generated from complementary sources, compared to 3Q24.
The year-on-year reduction in generation from the hydropower plants in 3Q25 is a reflection of the systemic condition of energy oversupply in the National Interconnected System (SIN). This situation resulted in the reduction, limitation or even effective cuts in generation, both in regard to wind and solar plants as well as hydropower operations in order to maintain equilibrium between load and generation and to guarantee the operational security of the system. As to hydrometeorological conditions, the third
quarter of 2025 reported a more favorable scenario than 2024, there thus being no hydrological justification for any reduction in 13
generation.
The increase in generation from the complementary plants in 3Q25 was driven by both wind plants, these producing 2,853 GWh (1,292 average MW), and also solar parks, responsible for an additional 559 GWh (253 average MW), increases of 30.7% and 67.2%, respectively, in relation to the third quarter 2024.
This performance benefited from the entry into commercial operations of the Serra do Assuruá Wind Complex, the completion of reconstruction work at the Paracatu 4 photovoltaic plant and initial operations at the Assú Sol Photovoltaic Complex. The combination of these assets was responsible for 1,266 GWh (573 average MW), growth of 1,045 GWh (473 average MW) when compared with 3Q24.
Also worth remembering that the decrease in the Company's hydropower generation does not necessarily cause deterioration in economic-financial performance. Similarly, an increase in this type of generation does not necessarily imply a growth in economic-financial performance. This is due to the application of the Energy Reallocation Mechanism (MRE), where the inherent hydrological risks of hydropower generation are shared proportionally among MRE participants.
| Generation | Average MW
| Generation by Complementary Source | Average MW
6,338
880
6,194
-15.8%
6,167
5,218
3,891
4,561
5,131
1,327
5,314
1,606
1,207
-2.7%
3Q24 3Q25 9M24 9M25
Hydro Complementary
6
34 15
96
1,207
60
33
1,327
+50.8%
1,606
+33.1%
145
712
325
118
880
41
43
118 8
135
350
942
210
780
596
107
53
13
80
3Q24 3Q25 9M24 9M25
Note:
The variation between the percentage calculated in GWh and average MW in 9M24 occurs due to 2024 was a leap year.
CurtailmentAccording to the National Electric System Operator's (ONS), there are three main categories of curtailment: Energetic (when it is impossible to allocate generation to the load), Electrical Reliability (due to reasons related to the electrical reliability of equipment external to the plants) and External Unavailability (caused by unavailability of facilities external to the plants). Of these, External Unavailability only allows the agent to potentially be reimbursed for generation limitations, as long as the conditions comply with the established Aneel and ONS parameters.
According to an analysis of the data published by the ONS in 3Q25, the wind and solar power plants operated by ENGIE Brasil Energia recorded 24% generation curtailment. The other plants that make up the National Interconnected System (SIN) recorded total availability of 22%. The Company's wind farms recorded a total reduction of 19%, the same percentage as the SIN, and 36% in solar, same as SIN, as can be seen in the following table:
| Curtailment by source | |||||||
3Q25 | 3Q24 | ||||||
Wind | Solar | Total | Wind | Solar | Total | ||
Curtailment ENGIE Brasil Energia | 19% | 36% | 24% | 13% | 20% | 15% | |
Curtailment SIN | 19% | 36% | 22% | 11% | 25% | 13% | |
14
| Curtailment by asset
| % Curtailment over 3Q25 Generation | average MW
430
(7%)
1,975
430
(22%)
1,545
6,167
Wind power plants | Commercial capacity (aMW) | 3Q25 (%) | 3Q24 (%) |
Trairi (CE) | 97.2 | 33% | 17% |
Santo Agostinho (RN) | 224.2 | 34% | 31% |
Campo Largo I and II (BA) | 359.0 | 15% | 9% |
Serra do Assuruá (BA) | 742.51 | 12% | 1% |
Umburanas (BA) | 213.3 | 19% | 7% |
6,597
Solar power plants 2
Commercial capacity (aMW)
3Q25 (%)
3Q24 (%)
Sol do Futuro (CE) 16.2 24% 19%
Floresta (RN) 25.1 39% 55%
Assú V (RN) 9.2 41% 30%
Assú Sol (RN) 171.61 31% -
Juazeiro (BA) | 34.8 | 44% | 33% |
Sertão Solar (BA) | 26.1 | 44% | 25% |
São Pedro (BA) | 16.0 | 48% | 31% |
Lar do Sol (MG) | 53.0 | 36% | 10% |
Paracatu (MG) | 34.0 | 35% | 9% |
Wind + solar
generation
Total
generation
Notes:
1 Operational commercial capacity on 09/30/2025.
2 Solar data available from April/2024.
Source: In-house study by ENGIE Brasil Energia based on assumptions published by the ONS and subject to updates.
Generation Curtailment
Gas TransportationIn 2025, TAG is 100% contracted through long-term legacy contracts with Petrobras and a connection contract to serve the Sergipe Hub in the Northeast region, all regulated by the ANP. Additionally, in 3Q25, 534 firm contracts (55 active) were signed with 24 carriers, totaling a volume of 12.6 million m³/day of transport capacity. This volume represents approximately 14% of the total volume contracted by TAG, and 16% considering only the integrated network (excluding the Urucu-Manaus Gas Transport Pipeline (GTA), where Petrobras remains the sole carrier).
Electric Energy Sales PortfolioWe show below the participation of the Company's customers (with the exception of CCEE and other revenues) in total physical
sales and in the total of Net Operating Revenue (NOR) of the generation segment.
15
| Breakdown of Customers by Physical Sales (%)
| Breakdown of Customers in Contracted Sales Comprising NOR of the Generation Segment (%)
34.2
37.5
35.5
56.5
36.4
60.3
56.8
60.0
7.1
5.5
5.7
4.5
47.4
4.1
48.5
46.9
3.1
50.0
47.7
3.9
48.4
48.5
6.5
45.0
3Q24 3Q25 9M24 9M25 3Q24 3Q25 9M24 9M25
Commercialization Strategy of Electric Energy
The Company pursues a commercial strategy of gradual sales of future energy availability for any given year as a means of mitigating the risk of exposure to spot prices (Price for Settlement of Differences - PLD) for that particular year. Electric energy sales are made during windows of opportunity that open when the market shows greater buying propensity. ENGIE Brasil Energia's energy balance based on proprietary commercial capacity and power purchasing agreements outstanding as of September 30, 2025, is as follows:
(in average MW) | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | In R$/MWh | |||
Own Resources | 4,794 | 5,193 | 5,207 | 5,206 | 5,207 | 5,166 | Auction Gross Price | Reference Date | Adjusted Gross Price | Price Net of PIS/ Cofins/P&D |
+ Purchases for Resale | 780 | 500 | 376 | 353 | 226 | 204 | ||||
= Total Resources (A) | 5,574 | 5,693 | 5,583 | 5,559 | 5,433 | 5,370 | ||||
Government Auction Sales1 | 1,992 | 2,180 | 2,154 | 2,144 | 2,144 | 2,144 | ||||
2005-NE-2010-30 | 200 | 200 | 200 | 200 | 200 | 200 | 115.1 | Dec-05 | 329.3 | 295.9 |
2006-NE-2009-30 | 493 | 493 | 493 | 493 | 493 | 493 | 128.4 | Jun-06 | 361.7 | 324.9 |
2006-NE-2011-30 | 148 | 148 | 148 | 148 | 148 | 148 | 135.0 | Nov-06 | 377.3 | 339.0 |
2007-NE-2012-30 | 256 | 256 | 256 | 256 | 256 | 256 | 126.6 | Oct-07 | 339.0 | 304.6 |
Proinfa | 19 | 19 | 10 | - | - | - | 147.8 | Jun-04 | 472.0 | 454.8 |
1st Reserve Energy Auction | 2 | - | - | - | - | - | 158.1 | Aug-08 | 379.9 | 366.1 |
Auction Mix (New Energy / Reserve) | 8 | - | - | - | - | - | - | - | 398.3 | 383.8 |
2014-NE-2019-25 | 10 | 10 | 10 | 10 | 10 | 10 | 206.2 | Nov-14 | 363.4 | 350.1 |
2014-NE-2019-20 | 82 | 82 | 82 | 82 | 82 | 82 | 139.3 | Nov-14 | 245.6 | 222.8 |
2015-NE-2018-20 | 46 | 46 | 46 | 46 | 46 | 46 | 188.5 | Aug-15 | 307.8 | 279.4 |
8th Reserve Energy Auction (Assú V/Floresta/Paracatu/Juazeiro/Sol do Futuro | 119 | 119 | 119 | 119 | 119 | 119 | 298.2 | Nov-15 | 471.4 | 427.8 |
7th Reserve Energy Auction (São Pedro) | 15 | 15 | 15 | 15 | 15 | 15 | 301.8 | Nov-15 | 515.3 | 467.7 |
2017-EN-2019-20 | 48 | 48 | 48 | 48 | 48 | 48 | 136.4 | Nov-14 | 246.0 | 223.2 |
2017-EN-2021-20 (Sertão Solar) | 27 | 27 | 27 | 27 | 27 | 27 | 189.5 | Nov-14 | 209.2 | 189.9 |
2024-EE-2025-2 | 17 | 17 | - | - | - | - | 162.6 | - | 162.6 | 147.6 |
2012-EN-2017-30 | 63 | 151 | 151 | 151 | 151 | 151 | 95.3 | Dec-12 | 184.2 | 167.2 |
2010-EN-2015-30 | 80 | 190 | 190 | 190 | 190 | 190 | 104.0 | Dec-10 | 231.5 | 210.1 |
Government Auction - Quotas regime | ||||||||||
2018 - Quotas (UHJA) - 2018-30 | 227 | 227 | 227 | 227 | 227 | 227 | - | Jul-17 | 220.0 | 209.9 |
2018 - Quotas (UHMI) - 2018-30 | 132 | 132 | 132 | 132 | 132 | 132 | - | Jul-17 | 253.0 | 241.3 |
| Energy Balance
16
+ Bilateral Sales | 2,958 | 2,766 | 2,272 | 1,767 | 930 | 748 | ||
= Total Sales (B) | 4,950 | 4,946 | 4,426 | 3,911 | 3,074 | 2,892 | ||
- Structural GSF Hedge (0.80) | 572 | 572 | 572 | 572 | 572 | 572 | ||
Balance (A - B) | 52 | 175 | 585 | 1,076 | 1,787 | 1,906 | ||
Sales average net price (R$/MWh) 2, 3: | 222.2 | 221.9 | 226.4 | |||||
Purchases average net price (R$/MWh) 4: | 178.8 | 159.3 | 165.9 |
1 XXXX-YY-WWW-ZZ, where:
XXXX year of auction
EE = existing energy or NE = new energy WWWW year of delivery start
supply contract duration (in years)
2 Sales price, including trading operations, is net of ICMS and taxes over revenue (PIS/Cofins, R&D), i.e. future inflation is not considered.
3 Disconsidering sales for quota regime (Jaguara and Miranda HPPs).
4 Purchase net prices, considering trading operations and benefits from PIS/Cofins credits, i.e. future inflation is not considered.
Notes:
The balance refers to the settlement point (net of losses of internal consumption of the plant).
The average prices are considered simply estimates and are based on financial planning revisions, not capturing volume changes, which are updated quarterly.
Earnings Release 3Q25 ENGIE Brasil Energia S.A.
Economic-Financial Performance | Results by segment - 3Q25 X 3Q24 | R$ million | |||||||
Net operating revenue | 2,549 | 643 | 151 | - | 3,343 | ||
Operational costs | (1,319) | (378) | (149) | - | (1,846) | ||
Gross income | 1,230 | 265 | 2 | - | 1,497 | ||
Selling, general and administrative expenses | (133) | (5) | (3) | - | (141) | 17 | |
Other operating revenues, net | (6) | - | - | - | (6) | ||
Disposal of subsidiary | 11 | - | - | - | 11 | ||
Equity income | - | - | - | 166 | 166 | ||
Income (loss) before financial results and taxes | 1,102 | 260 | (1) | 166 | 1,527 | ||
3Q24 | |||||||
Net operating revenue | 2,168 | 291 | 78 | - | 2,537 | ||
Operational costs | (1,063) | (92) | (79) | - | (1,234) | ||
Gross income (loss) | 1,105 | 199 | (1) | - | 1,303 | ||
Selling, general and administrative expenses | (122) | (7) | (1) | - | (130) | ||
Other operating revenues, net | 3 | 25 | - | - | 28 | ||
Disposal of equity interest in a jointly controlled subsidiary | - | - | - | (1) | (1) | ||
Equity income | - | - | - | 182 | 182 | ||
Income (loss) before financial results and taxes | 986 | 217 | (2) | 181 | 1,382 | ||
Change | |||||||
Net operating revenue | 381 | 352 | 73 | - | 806 | ||
Operational costs | (256) | (286) | (70) | - | (612) | ||
Gross income | 125 | 66 | 3 | - | 194 | ||
Selling, general and administrative expenses | (11) | 2 | (2) | - | (11) | ||
Other operating revenues (expenses), net | (9) | (25) | - | - | (34) | ||
Disposal of subsidiary | 11 | - | - | - | 11 | ||
Disposal of equity interest in a jointly controlled subsidiary | - | - | - | 1 | 1 | ||
Equity income | - | - | - | (16) | (16) | ||
Income (loss) before financial results and taxes | 116 | 43 | 1 | (15) | 145 | ||
Electric energy | ||
Generation¹ Transmission Trading Gas Consolidated transportation | ||
3Q25 | ||
¹ Generation and sale of electric energy from the Company's portfolio ("Generation").
The Company's financial result is not allocated by segment since Management administers the cash flow on a consolidated and corporate basis.
Net Operating Revenue
| Operating revenue by segment - 3Q25 X 3Q24 | R$ million
Electric Energy | ||
Generation Transmission Trading Consolidated | ||
3Q25 | ||
Free contracting environment1 | 1,132 | - | - | 1,132 | |
Regulated contracting environment2 | 1,049 | - | - | 1,049 | |
Construction revenue | - | 386 | - | 386 | |
Remuneration of concession assets | 114 | 235 | - | 349 | |
Transactions in the short-term market | 203 | - | - | 203 | |
Energy trading operations | - | - | 151 | 151 | |
Service rendered revenue | 42 | 22 | - | 64 | |
Indemnifications | 3 | - | - | 3 | |
Other revenues | 6 | - | - | 6 | |
Net operating revenue | 2,549 | 643 | 151 | 3,343 | |
3Q24 | |||||
Free contracting environment | 958 | - | - | 958 | |
Regulated contracting environment | 974 | - | - | 974 | |
Construction revenue | - | 66 | - | 66 | |
Remuneration of concession assets | 109 | 204 | - | 313 | |
Transactions in the short-term market | 75 | - | 1 | 76 | |
Energy trading operations | - | - | 77 | 77 | |
Service rendered revenue | 39 | 21 | - | 60 | |
Other revenues | 13 | - | - | 13 | |
Net operating revenue | 2,168 | 291 | 78 | 2,537 | |
Change | |||||
Free contracting environment | 174 | - | - | 174 | |
Regulated contracting environment | 75 | - | - | 75 | |
Construction revenue | - | 320 | - | 320 | |
Remuneration of concession assets | 5 | 31 | - | 36 | |
Transactions in the short-term market | 128 | - | (1) | 127 | |
Energy trading operations | - | - | 74 | 74 | |
Service rendered revenue | 3 | 1 | - | 4 | |
Indemnifications | 3 | - | - | 3 | |
Other revenues | (7) | - | - | (7) | |
Net operating revenue | 381 | 352 | 73 | 806 |
18
1 Free consumers and trading companies.
2 Distribution companies.
In 3Q25, net operating revenue increased 31.8% (R$ 806 million) year-over-year from R$ 2,537 million to R$ 3,343 million.
This variation stems largely from the following effects: (i) an increase of R$ 381 million (17.6%) in net operating revenue from the generation and energy sales portfolio; (ii) an increase of R$ 352 million (121.0%), substantially due to progress made on the construction of the Asa Branca Transmission System which had a positive impact on growth in operating revenue for the transmission segment; and (iii) an increase of R$ 73 million (93.6%) in the trading segment. More details on the transmission and trading segments are described under specific headings.
| Net Operating Revenue Change by Segment | R$ million
NOR 3Q24
Price and sales volume
CCEE
Rem. of financial asset and other
Transmission
Trading
19
(11%)
291 (3%)
2,549
(76%)
2,168
(85%)
+31.8%
3,343
151 643 (5%)
(19%)
128
249
73
352
4
2,537
78
NOR 3Q25
Generation and portfolio's sale
Comments on Variation in Net Operating Revenue
Generation and Sales of Energy from the Portfolio| Net Average Selling Price and Sales Volume
The average selling price of energy, net of charges on revenue and trading operations was R$ 211.61/MWh in 3Q25. This result was 2.0% less than 3Q24, when the average prices were R$ 215.96/MWh.
During the course of the years 2024 and 2025, there were reimbursements due to the delivery of wind and solar power in amounts lower than in the relevant regulated environment agreements signed with the distributors. Excluding the impact from the reimbursements during the quarters, the net average selling price of energy fell from R$ 226.92/MWh in 3Q24 to R$ 219.73/MWh in 3Q25, a reduction of 3.2%.
The price reduction between comparative periods under analysis was largely due to: (i) the continuous improvement in hydrological conditions recorded over the past few years combined with the increase in the supply of renewable energy and the growth of distributed generation, factors contributing to the lower energy prices in the Free Contracting Environment (ACL); (ii) the result of the inclusion of the agreements related to the acquisition of the Santo Antônio do Jari and Cachoeira Caldeirão hydropower plants; but partially attenuated by the (iii) monetary restatement of prevailing long term agreements. In addition, deterioration of the hydrological scenario in 2024 driving the increase in energy prices, had no significant impact in 3Q25, given the low levels of uncontracted energy in our portfolio.
The volume of energy sold in contracts, net of trading operations, increased from 8,942 GWh (4,050 average MW) in 3Q24 to
10,308 GWh (4,668 average MW) in 3Q25, a growth of 1,366 GWh (618 average MW), or 15.3% between the comparable periods.
The increase in energy sales volume in the quarter was driven mainly by the additional sold to distributors in the light of the acquisition of Santo Antônio do Jari and Cachoeira Caldeirão hydropower plants and the increase in the free contracting environment on the back of growth in proprietary installed capacity over the intervening period between the respective quarters. This reflected full entry into commercial operations of the Santo Agostinho Wind Complex in the second half of 2024, and the partial startup in commercial operations at the Serra do Assuruá Wind Complex and the Assú Sol Photovoltaic Complex during 2024 and 2025.
The variations in sales volumes and in average selling prices combined produced an increase of R$ 249 million in the Company's
net operating revenue.
| Net Average Selling Price1 | Sales Volume2
-2.0%
-3.4%
216.0
211.6
221.4
214.0
3Q24 3Q25 9M24 9M25
1 Net of sale taxes and trading operations.
| Energy Transactions
Free Contracting Environment:
20
+15.3%
4,668
4,050
+11.7%
4,455
3,990
3Q24 3Q25 9M24 9M25
2 Net of trading operations.
Revenue from sales to free consumers and trading companies increased by R$ 174 million (18.2%) between the quarters under analysis from R$ 958 million in 3Q24 to R$ 1,132 million in 3Q25. The variation is the result of the increase of 1,145 GWh (518 average MW) in energy sales volume (R$ 197 million), attenuated by a decrease of 2.4% in net average selling price (R$ 23 million).
The variation in energy volume sold is due in large part to the startup in operations at the Serra do Assuruá Wind Complex and the Assú Sol Photovoltaic Complex resulting in greater available energy in the Company's portfolio. Conversely, the reduction in net average selling price was a reflection of the decrease in energy prices on the free market, in turn, in the light of an improved hydrological scenario as explained above, combined with the increase in supply of renewable energy over recent years, factors attenuated by monetary restatement of ongoing contracts.
Regulated Contracting Environment:
Revenue from sales to distributors reached R$ 1,049 million in 3Q25, R$ 75 million (7.7%) greater than the R$ 974 million reported in 3Q24. The positive variation was a reflection of the following factors: (i) R$ 62 million due to an increase of 221 GWh (100 average MW) in sales volume; and (ii) R$ 13 million from the 1.4% hike in net average selling prices.
The increase in sales volumes on a year-over-year comparative basis was due largely to energy transacted by the hydropower plants acquired in 3Q25, namely Santo Antônio do Jari and Cachoeira Caldeirão. The increase in net average selling prices between the quarters under comparison in analysis was driven largely by (i) monetary restatement of selling prices in the compared quarters; but attenuated by (ii) the inclusion of the agreements linked to the acquisition of the Santo Antônio do Jari and Cachoeira Caldeirão hydropower plants.
Disregarding the impact of the aforementioned reimbursements, the average net sales price of distributors increased by 2.0% between the quarters.
| Transactions in the Short-term Energy Market
In 3Q25, revenue reported for the short-term market was R$ 203 million, compared with 3Q24 when the same item was R$ 75 million, representing a growth of R$ 128 million (170.7%) between the quarters under analysis. Further explanations on these operations and on the variation can be found under the "Details of short-term operations".
Operational Costs
Electric power purchases | 303 | - | 150 | 453 | |
Depreciation and amortization | 342 | 3 | - | 345 | |
Construction costs | - | 344 | - | 344 | |
Charges for the use of power grid and connection | 208 | - | - | 208 | |
Materials and third-party services | 138 | 12 | - | 150 | |
Transactions in the short-term market | 137 | - | - | 137 | |
Personnel | 70 | 4 | - | 74 | |
Royalties | 53 | - | - | 53 | |
Insurance | 43 | 1 | - | 44 | |
Unrealized losses on trading operations | - | - | (1) | (1) | |
Hydrological risk renegotiation | (9) | - | - | (9) | |
Other operational costs, net | 34 | 14 | - | 48 | |
Operational costs | 1,319 | 378 | 149 | 1,846 | |
3Q24 | |||||
Electric power purchases | 315 | - | 83 | 398 | |
Depreciation and amortization | 260 | 3 | - | 263 | |
Construction costs | - | 71 | - | 71 | |
Charges for the use of power grid and connection | 176 | - | - | 176 | |
Materials and third-party services | 109 | 12 | - | 121 | |
Transactions in the short-term market | 16 | - | - | 16 | |
Personnel | 62 | 3 | - | 65 | |
Royalties | 58 | - | - | 58 | |
Insurance | 30 | 1 | - | 31 | |
Unrealized losses on trading operations | - | - | (4) | (4) | |
Other operational costs, net | 37 | 2 | - | 39 | |
Operational costs | 1,063 | 92 | 79 | 1,234 | |
Change | |||||
Electric power purchases | (12) | - | 67 | 55 | |
Depreciation and amortization | 82 | - | - | 82 | |
Construction costs | - | 273 | - | 273 | |
Charges for the use of power grid and connection | 32 | - | - | 32 | |
Materials and third-party services | 29 | - | - | 29 | |
Transactions in the short-term market | 121 | - | - | 121 | |
Personnel | 8 | 1 | - | 9 | |
Royalties | (5) | - | - | (5) | |
Insurance | 13 | - | - | 13 | |
Unrealized losses on trading operations | - | - | 3 | 3 | |
Hydrological risk renegotiation | (9) | - | - | (9) | |
Other operational costs, net | (3) | 12 | - | 9 | |
Operational costs | 256 | 286 | 70 | 612 |
| Costs by segment - 3Q25 x 3Q24 | R$ million
Electric Energy | ||
Generation Transmission Trading Consolidated | ||
3Q25 | ||
21
Operational costs increased by R$ 612 million (49.6%) between the compared quarters from R$ 1,234 million in 3Q24 to R$ 1,846 million in 3Q25. This variation was substantially due to a combination of the following factors: (i) a growth of R$ 286 million (310.9%) in the costs of the transmission segment, mainly increased construction costs of the Asa Branca Transmission System; (ii) an increase of R$ 256 million (24.1%) in the costs of the energy generation and sale of the Company's portfolio segment; and (iii) an increase of R$ 70 million (88.6%) in the costs of energy trading operations.
| Operational Costs Change | R$ million
+49.6%
-5
1,846
32
-12 67
273
149
(8%)
378
(20%)
29
82
9 3 13
1,234
79
92
1,063
121
1,319
(71%)
22
Cost 3Q24
CCEE
Depreciation and amortization
Materials and third-party services
Charges for power grid and connection
Purchases for portfolio
Royalties
Other
Construction costs
Cost 3Q25
Generation and sales from portfolio Transmission Trading
The change in the energy generation and sales from the portfolio segment is essentially due to the movement of the main components as follows:
Comments on Variations in Operational Costs
Generation and Energy Sales from the PortfolioEnergy purchases: between 3Q24 and 3Q25, there was a reduction of R$ 12 million (3.8%) in energy purchases mainly driven by a combination of a decrease of 7.3% in net average price of energy purchases (R$ 23 million) and the increase of 76 GWh (35 average MW) in purchased volumes (R$ 11 million). The increase in volume is due to the rise in purchases for the Company's portfolio management. The variation in average purchase prices reflects an improvement in the hydrological scenario prevailing at the time of contracting dates as mentioned above, combined with the increase in supply of renewable energy over recent years, factors which have depressed energy prices in the free contracting market.
Depreciation and amortization: an increase of R$ 82 million (31.5%), between the quarters under analysis. The variation is a reflection mainly of: (i) the entry into commercial operation of the Serra do Assuruá Wind Complex and the Assú Sol Photovoltaic Complex as from August 2024 and January 2025, respectively; (ii) the complete startup in commercial operations of wind farms comprising the Santo Agostinho Wind Complex during the course of 2024; (iii) the initial amortization of the right of use of the assets in the form of intangibles and linked to the acquisition of the Juazeiro, São Pedro, Sol do Futuro, Sertão Solar and Lar do Sol photovoltaic complexes ("Photovoltaic Complexes") and (iv) the increase in depreciation of the recently acquired Santo Antônio do Jari and Cachoeira Caldeirão subsidiaries.
Charges for use of the electric energy network and connection: increase of R$ 32 million (18.2%) between the quarters analyzed, resulting mainly from: (i) the entry into partial commercial operation of the Serra do Assuruá Wind Complex and the Assú Sol Photovoltaic Complex; (ii) the acquisition of the Santo Antônio do Jari and Cachoeira Caldeirão subsidiaries; and (iii) the annual transmission and distribution tariff readjustment.
Third party material and services: increase of R$ 29 million (26.6%) between the comparable quarters. The main drivers are the result of the following factors: (i) entry into commercial operation of the Serra do Assuruá and Santo Agostinho wind complexes and the Assú Sol Photovoltaic Complex; (ii) the acquisition of the Photovoltaic Complexes; and (iii) provision of consulting and advisory services.
Transactions in the short-term energy market: the costs of these transactions posted an increase of R$ 121 million (756.3%) between the quarters analyzed. More explanations on these operations and in relation to the variation are to be found under the heading "Details of short-term operations."
Renegotiation of hydraulic risk: in September 2021, the National Electric Energy Agency (Aneel) published Ratification Resolution 2932/2021. This ratified the rollover of grant maturities for hydropower plants, participants in the Energy Reallocation Mechanism (MRE) as a means of compensating for accumulated losses up to December 31, 2020. This measure relates to the revised treatment given the period prior to the renegotiation of hydrologic risk pursuant to Law 14.182 of July 12, 2021 and complementary to Law 13.203 of November 8, 2015. On April 1, 2025, Aneel published Ratification Resolution 3.439/2025, which extended the coverage period of the impacts associated with the MRE up to June 30, 2023, recognizing that the losses on the part of the hydropower plants continued accumulating post 2020. Consequently, the Company received an extended concession term for its plants from 1 to 3 days, the effect on the result being an additional R$ 9 million in 2025.
Other costs in this segment showed no significant variations between the quarters under analysis.
Operational Result from the Energy Transmission SegmentThe Company has primary responsibility for the construction and installation of infrastructure pertaining to the Gralha Azul, Novo Estado, Gavião Real, Asa Branca and Graúna transmission systems and is exposed to the risks and benefits of these constructions. Consequently, based on prevailing accounting practices, the Company books revenue over the course of the implementation of the transmission infrastructure for an amount corresponding to the construction costs plus a gross margin on the construction services provided. Expenditures incurred in the construction are recognized in the cost of the transmission infrastructure. The Annual Allowed Revenue (RAP) is received once the transmission system goes into commercial operations. Thus, only resources generated from operational activities are received from then onwards. The Gralha
Azul and Novo Estado transmission systems went into full commercial 23
operations on February 19 and 27, 2023, respectively. On July 8, 2024, the Company finalized the implementation of the Gavião Real Transmission System project with the complete energization as incorporated in the Delivery and Acceptance Certificate (TLD) issued by the National System Operator (ONS) on July 12, 2024. Additionally on July 18, 2025, the Company took over the operation of the brownfield stretch of the Graúna Transmission System, corresponding to approximately 5% of the project's total RAP.
The gross result of the energy transmission segment reached a positive R$ 265 million in 3Q25, an increase of R$ 66 million (33.2%) compared to the same quarter of 2024 when the segment posted R$ 199 million. The variations stem largely from (i) the positive effect of R$ 47 million (940.0%) in the variation of the net result of construction revenues and costs (increases of R$ 320 million and R$ 273 million, respectively), originating principally from progress of work on the Asa Branca Transmission System;
and (ii) the growth of R$ 31 million (15.2%) in the remuneration of the concession assets, caused in particular by the increase in the nominal balance due to advancing construction work on the Asa Branca Transmission System, attenuated by the reduction in inflation indices between the comparable quarters.
RAP value, net of PIS and Cofins taxes, received in 3Q25 was R$ 203 million, (R$ 189 million in 3Q24), being R$ 181 million (R$ 168 million in 3Q24) corresponding to the contract asset amortization, registered as a counterbalancing item to the contract asset, and R$ 22 million (R$ 21 million in 3Q24) relative to revenue from O&M services rendered.
Below is the composition of the regulatory transmission Ebitda:
(in R$ million) | 3Q25 | 3Q24 | Change |
RAP, net of PIS and Cofins | 203 | 189 | 14 |
Operational costs | (31) | (18) | (13) |
Selling, general and administrative expenses | (5) | (7) | 2 |
Regulatory transmission Ebitda | 167 | 164 | 3 |
The Company operates in the physical energy trading market to leverage results from energy price variations within pre-set limits of risk. Energy trading operations are transacted in an active market and for accounting purposes are defined as financial instruments according to their fair value. This is principally due to the absence of any commitment to match purchase and sale operations, flexibility being permitted to manage the contracts and obtain results through price variations in the market.
There was a positive variation of R$ 3 million between the quarters under analysis, driven by the positive impact of R$ 7 million in short term transactions, but offset by a decline of R$ 3 million resulting from the mark to market of the transactions for future delivery when making the comparison between periods - that is the difference between contracted and market prices.
Details of Short-Term OperationsShort-term operations are classified as energy purchase or sale operations, the principal objective being the management of the Company's exposure on the CCEE. Consequently, the price of these operations is characterized by the linkage with the Price for Settlement of Differences (PLD). This item also includes the transactions conducted through the CCEE, given their volatile and seasonal nature, therefore, short-term, of the results originating from accounting movement in the CCEE. Additionally, the long and short positions are settled at the PLD, thus, similar to the short-term operations described above.
In relation to the transactions conducted through the CCEE, the various monthly credit or debit entries to the account of a Board agent are summarized in a single billing as a receivable or a payable. This therefore requires an entry to either an income or an expense item. In this context, it is worth pointing out that due to adjustments in the Company's portfolio management strategy, changes have been taking place in the profile of the mentioned billings. Such fluctuations complicate the direct comparison of the elements comprising each billing for the periods being analyzed - the reason for including this specific topic. The strategy allows us to analyze the fluctuations of the principal elements involved in spite of allocation being either to an income or expenses
account according to the credit or debit nature of the billing to which they relate. 24
Generically, these elements are revenues or expenses arising, for example, (i) from the application of the Energy Reallocation Mechanism (MRE); (ii) from the Generation Scaling Factor (GSF), triggered when generation of plants, part of the MRE, is smaller or greater (Secondary Energy) than the allocated energy; (iii) from the so-called "submarket risk"; (iv) dispatch driven by the Risk Aversion Curve (CAR); (v) the application of System Service Charges (ESS), resulting in dispatch which diverges from the thermal plants order of merit; and (vi) naturally, exposure (a short or long position in the monthly accounting) and settled at the PLD.
| Net Result of Short-term Operations | R$ million
Generation Trading Consolidated | ||||
Net operating revenue | 3Q25 | 203 | - | 203 |
Operational costs | (137) | - | (137) | |
Net result | 66 | - | 66 | |
3Q24 | ||||
Net operating revenue | 75 | 1 | 76 | |
Operational costs | (16) | - | (16) | |
Net result | 59 | 1 | 60 | |
Change | ||||
Net operating revenue | 128 | (1) | 127 | |
Operational costs | (121) | - | (121) | |
Net result | 7 | (1) | 6 | |
In 3Q25 and 3Q24, net results (the difference between revenues and costs - less taxes) from short-term transactions - more especially conducted within the scope of the CCEE - were a positive R$ 66 million and a positive R$ 60 million, respectively. The amount represents an increase of R$ 6 million between compared periods, reflecting the result of transactions in the energy generation and sales segment of the portfolio.
These variations were largely a result of a combination of the following factors: (i) the increase in free energy due to the strategy of seasonalized energy allocation in the periods under consideration plus an increase in PLD (Price for Settlement of Differences); attenuated (ii) by the negative impact from the reduction in the MRE (GSF) Adjustment Factor, in the light of the allocation of physical guarantee and generation of participating plants (average GSF went from 79.2% in 3Q24 to 64.9% in 3Q25); and (iii) by the negative effect on the MRE, due to the lower hydropower generation in relation to the preceding year and the consequent reduction in values to be reimbursed by other members of the MRE. Overall, there was a positive contribution from the closing of operations at month end, restatements, and adjustments between the quarters analyzed.
In December 2024, Aneel established PLD maximum and minimum limits for 2025 at R$ 751.73/MWh and R$ 58.60/MWh, respectively. The following table shows average PLD values for the submarkets in which the Company operates, in MWh.
Average PLD in R$/MWh | 3Q25 | 3Q24 | Chg. (%) |
South | 253.06 | 171.21 | 47.8% |
Southeast/Center-West | 252.51 | 171.15 | 47.5% |
Northeast | 240.03 | 143.80 | 66.9% |
The Company posted an increase in selling, general and administrative expenses of R$ 11 million (8.5%) between 3Q25 and 3Q24. Variations between the quarters analyzed largely arose from the growth in the generation segment in the same amount, impacted substantially by the increase in expenses with IT and digitalization services.
Other Operational Revenues (Expenses), NetIn 3Q25, the Company booked R$ 6 million in relation to the generation segment with respect to the writing down of assets pertaining to the Paracatu Photovoltaic Complex due to the upgrading of solar tracker technology. In the transmission segment, an amount of R$ 25 million was booked in 3Q24 with a positive impact on the result based mainly on the expectation of a revision in the structure of investments made and the remuneration rate of capital, this resulting in modifications in the values of future RAP income.
Disposal of Subsidiary 25In 3Q25 the Company posted R$ 11 million, relating to receivables pursuant to the sale agreement of the Pampa Sul subsidiary, concluded in 2023.
Equity Income - Gas TransportationThe Company holds a 17.5% direct corporate stake in TAG. TAG's equity income result for the quarters under analysis is composed of the following items:
3Q25 3Q24
Income statement (in R$ million) | 100% | Company's share1 | 100% | Company's share1 |
Net operational revenue | 2,305 | 403 | 2,209 | 387 |
Costs of services provided | (590) | (103) | (425) | (74) |
Gross income | 1,715 | 300 | 1,784 | 313 |
General and administrative expenses | (41) | (7) | (46) | (8) |
Income before financial result and taxes | 1,674 | 293 | 1,738 | 305 |
Financial result | (532) | (93) | (475) | (83) |
Income before taxes | 1,142 | 200 | 1,263 | 222 |
Income tax and social contribution | (194) | (34) | (225) | (40) |
TAG's net income | 948 | 166 | 1,038 | 182 |
1Until January 9, 2024, ENGIE Brasil Energia held 32.5% of TAG shares, and from January 10, 2024 it held 17.5% of shares.
The reconciliation of TAG's Ebitda is shown in the following table:
3Q25 3Q24
Ebitda (in R$ million) | 100% | Company's share | 100% | Company's share |
Income before financial result and taxes | 1,674 | 293 | 1,738 | 305 |
Depreciation and amortization | 180 | 32 | 167 | 29 |
Amortization of mais valia | 150 | 26 | (10) | (2) |
Ebitda¹ | 2,004 | 351 | 1,895 | 332 |
Ebitda Margin 86.9% 85.8%
¹ In accordance with the guidelines established in CVM Resolution No. 156 (RCVM 156) and Circular Letter CVM/SNC/SEP No. 01/2023, of June 23, 2022 and February 13, 2022, respectively.
There was a reduction between 3Q24 and 3Q25 in equity income of R$ 16 million (8.8%) from R$ 182 million to R$ 166 million, respectively, the consequence of a decrease in net income at TAG.
In relation to the reduction in the result at TAG, the variation is mainly a reflection of (i) the revision of the useful life of mais valia (added value) carried out in 2024 - considering that it was initially limited to the concession period of the legacy contracts and, after the New Gas Law, it was revised to the same useful life of its assets; (ii) the increase in net financial expenses: (ii.i) due to foreign exchange variation and monetary restatement in relation to debt and (ii.ii) the reduction of interest on financial investments and derivatives; attenuated (iii) by adjustments in 2024 made to contracts indexed to the IGPM; (iv) the reduction in currency variation on revenue from the GASENE System transportation agreement; and (v) an increase in the depreciation of new fixed assets.
| Balance Sheet
Balance Sheet | 09/30/2025 | 12/31/2024 |
ASSETS Current assets | 3,774 | 4,443 |
Cash and cash equivalents | 1,852 | 2,325 |
Accounts receivable from clients | 1,701 | 1,830 |
Other current assets | 221 | 288 |
Non-current assets | 29,123 | 28,955 |
Restricted deposits | 1,058 | 326 |
Other non-current assets | 164 | 155 |
Property, plant and equipment | 25,147 | 25,727 |
Intangible | 2,754 | 2,747 |
Total | 32,897 | 33,398 |
LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities | 3,564 | 4,377 |
Debt instruments | 2,602 | 3,432 |
Derivative financial instruments - hedge | 26 | 7 |
Other current liabilities | 936 | 938 |
Non-current liabilities | 22,004 | 22,409 |
Debt instruments | 15,063 | 16,419 |
Derivative financial instruments - hedge | 262 | 77 |
Deferred income taxes and social contribution | 6,010 | 5,204 |
Other non-current liabilities | 669 | 709 |
Shareholders' equity | 7,329 | 6,612 |
Total | 32,897 | 33,398 |
TAG's principal asset and liability groups as of September 30, 2025 and December 31, 2024 were as follows:
26
Ebitda and Ebitda Margin
| Ebitda by segment - 3Q25 x 3Q24 | R$ million
Electric Energy | |
Generation Transmission Trading Gas Consolidated Transportation | |
3Q25 | |
Income (loss) before financial results and taxes | 1,102 | 260 | (1) | 166 | 1,527 |
Depreciation and amortization | 352 | 3 | - | - | 355 |
Ebitda1 | 1,454 | 263 | (1) | 166 | 1,882 |
Disposal of subsidiary | (11) | - | - | - | (11) |
Adjusted Ebitda | 1,443 | 263 | (1) | 166 | 1,871 |
Adjusted Ebitda margin | 56.6% | 40.9% | (0.7%) | - | 56.0% |
3Q24 | |||||
Income (loss) before financial results and taxes | 986 | 217 (2) | 181 | 1,382 | |
Depreciation and amortization | 269 | 3 - | - | 272 | |
Ebitda | 1,255 | 220 (2) | 181 | 1,654 | |
Subsidiary acquisition costs | 10 | - - | - | 10 | |
Disposal of equity interest in a jointly controlled subsidiary | - | - - | 1 | 1 | |
Adjusted Ebitda | 1,265 | 220 (2) | 182 | 1,665 | |
Adjusted Ebitda margin | 58.3% | 75.6% (2.6%) | - | 65.6% | |
Change | |||||
Income (loss) before financial results and taxes | 116 | 43 1 | (15) | 145 | |
Depreciation and amortization | 83 | - - | - | 83 | |
Ebitda | 199 | 43 1 | (15) | 228 | |
Disposal of subsidiary | (11) | - - | - | (11) | |
Subsidiary acquisition costs | (10) | - - | - | (10) | |
Disposal of equity interest in a jointly controlled subsidiary | - | - - | (1) | (1) | |
Adjusted Ebitda | 178 | 43 1 | (16) | 206 | |
Adjusted Ebitda margin | (1.7 p.p.) | (34.7 p.p.) 1.9 p.p. | - | (9.6 p.p.) | |
27
¹ In accordance with the guidelines established in CVM Resolution No. 156 (RCVM 156) and Circular Letter CVM/SNC/SEP No. 01/2023, of June 23, 2022 and February 13, 2022, respectively.
Between 3Q25 and 3Q24, adjusted Ebitda increased R$ 206 million (12.4%) from R$ 1,665 million in 3Q24 to R$ 1,871 million in 3Q25. The variation was driven by the positive impacts of (i) R$ 178 million (14.1%) in the Company's energy generation and sales of energy from the portfolio segment; (ii) R$ 43 million (19.5%) originating from the energy transmission segment; and (iii) R$ 1 million (50.0%) from the energy trading segment. These effects were attenuated by the negative effect of R$ 16 million (8.8%) due to a lower result from the corporate stake in the jointly controlled subsidiary - TAG.
The key variations in the adjusted Ebitda lie in the electric energy generation and sale from the portfolio segment, described in item (i) above, positive effects of which were: (i) R$ 249 million from the combination of variation in energy volumes sold and net average selling price; (ii) a reduction of R$ 12 million in energy purchases; (iii) an additional R$ 9 million booked with respect to the renegotiation of hydrological risk;
| Adjusted Ebitda1 | R$ million
19
+6.4%
1,654
1,882
11
+12.4%
1,871
5,778
5,432
1,348
1,665
6,780
(11)
5,797
and (iv) R$ 7 million from a positive impact related to transactions conducted in the short-term market. These
3Q24 3Q25
9M24 9M25
positive effects were attenuated by the following variations with negative impacts: (i) an increase of R$ 32 million in overheads as a result of the use of the electricity grid and connections; (ii) an increase of R$ 29 million in the costs of materials and third party services; and (iii) R$ 38 million relative to other operational costs and administrative expenses.
Non recurrent Adjusted Ebitda
1 Adjusted Ebitda: net income + income tax and social contribution + financial results + depreciation and amortization + impairment + non recurrent effects.
Additionally, in 3Q25, adjusted Ebitda was positively impacted by the transmission segment and largely a combination of the following factors: (i) R$ 47 million growth in the variation of the net result of construction revenues and costs; (ii) R$ 31 million increase in remuneration of concession assets; (iii) a negative effect of R$ 25 million, when comparing the quarters due to the
recognition of the revision of the contractual asset in 3Q24; (iv) a decrease of R$ 12 million in the O&M margin (O&M RAP, net of costs); and (v) R$ 2 million reduction in expenses with selling, general and administrative expenses.
(in R$ million) | 3Q25 | 3Q24 | Chg. (%) | 9M25 | 9M24 | Chg. (%) |
Recurrent net income | 738 | 658 | 12.2 | 2,132 | 3,213 | (33.6) |
(+) Income tax and social contribution | 223 | 237 | (5.9) | 662 | 1,255 | (47.3) |
(+) Net financial result | 566 | 487 | 16.2 | 1,995 | 1,529 | 30.5 |
(+) Depreciation and amortization | 355 | 272 | 30.5 | 1,008 | 783 | 28.7 |
Ebitda | 1,882 | 1,654 | 13.8 | 5,797 | 6,780 | (14.5) |
Non-recurrent effects | ||||||
(+) Subsidiary acquisition costs | - | 10 | (100.0) | - | 10 | (100.0) |
(+) Impairment (reversal) | - | - | - | - | (31) | (100.0) |
(+) Disposal of subsidiary | (11) | - | (100.0) | (19) | 9 | (311.1) |
(+) Disposal of equity interest in a jointly controlled subsidiary | - | 1 | 100.0 | - | (1.336) | (100.0) |
Adjusted Ebitda | 1,871 | 1,665 | 12.4 | 5,778 | 5,432 | 6.4 |
Statutory transmission Ebitda (IFRS) | (263) | (220) | 19.5 | (907) | (699) | 29.8 |
Regulatory transmission Ebitda (RAP) | 167 | 164 | 1.8 | 506 | 491 | 3.1 |
Statutory quota holders Ebitda (IFRS) | (192) | (182) | 5.5 | (613) | (577) | 6.2 |
Regulatory quota holders Ebitda | 180 | 169 | 6.5 | 520 | 494 | 5.3 |
Ebitda adjusted by transmission and quota effects | 1,763 | 1,596 | 10.5 | 5,284 | 5,141 | 2.8 |
To enable the reconciliation of net income with Ebitda as well as the impacts of regulatory adjustments in transmission quota holders, we present the following table:
28
| Ebitda Change | R$ million
+13.8%
+12.4%
+10.5%
(36)
3
1,763
108
96
12
1,871
1,882
(32)
11
(29)
1,654
11
1,665
277
10 1
(56)
(69)
1,596
263
(14%)
166
(9%)
1,253
(76%)
1,263
(76%)
1,430
(81%)
1,250
(78%)
1,442
(77%)
1,453
(77%)
182
(11%)
164
(10%)
182
(11%)
220
(13%)
181
(11%)
220
(13%)
166
(9%)
167
(9%)
166
(9%)
263
(14%)
(13)
(16)
Ebitda 3Q24 Non-recurring
Adjusted
IFRS*
Ebitda
Operating and Charges for
Material and
Other costs
Transmission Equity income
Ebitda
IFRS*
Adjusted
Non-recurring Ebitda 3Q25
Ebitda 3Q24
adjustment
adjusted by trans./quota 3Q24
commercial performance
power grid and connection
third-party services
and operating expenses
(TAG)
adjusted by trans./quota 3Q25
adjustment
Ebitda 3Q25
Generation and trading Equity income (TAG) Transmission
* IFRS: International Financial Reporting Standards.
1 Considering the result from generation and trading segments.
(in R$ million) | 3Q25 | 3Q24 | Chg. (R$) | 9M25 | 9M24 | Chg. (R$) |
Income from financial investments | 196 | 117 | 79 | 493 | 427 | 66 |
Other financial income | 25 | 16 | 9 | 83 | 62 | 21 |
Total financial income | 221 | 133 | 88 | 576 | 489 | 87 |
Debt: | ||||||
Interest | (500) | (260) | (240) | (1,171) | (1,276) | 105 |
Monetary restatement | (119) | (137) | 18 | (694) | (562) | (132) |
Other financial expenses, net | (38) | (48) | 10 | (226) | 356 | (582) |
Total financial expenses | (657) | (445) | (212) | (2,091) | (1,482) | (609) |
Concessions payable (Use of Public Asset): | ||||||
Monetary restatement | (8) | (51) | 43 | (115) | (166) | 51 |
Present value restatement | (122) | (124) | 2 | (365) | (370) | 5 |
Total concession payable expenses (Use of Public Asset) | (130) | (175) | 45 | (480) | (536) | 56 |
Financial result | (566) | (487) | (79) | (1,995) | (1,529) | (466) |
29
Financial Income: in 3Q25, financial income reached R$ 221 million, R$ 88 million or 66.2% more than the R$ 133 million reported in 3Q24, mainly due to the increase of R$ 79 million in revenue from financial investments. Growth was largely driven by the increase in average outstandings held in the form of financial investments in the periods in question and by an increase in CDI rates.
Financial Expenses: financial expenses in 3Q25 were R$ 657 million, that is R$ 212 million or 47.6% more than recorded for 3Q24, when the same expenses stood at R$ 445 million. The main variations shown were due to the increase of R$ 222 million in debt between the quarters analyzed, a reflection of (i) a growth of R$ 240 million in interest charges on debt by virtue of the Company's 12th, 13th, 14th and 15th debenture issuances in July 2024, October 2024, March 2025 and July 2025, respectively as well as the year-over-year increase in CDI and TJLP; albeit offset by (ii) a reduction of R$ 18 million relative to monetary restatement following the reduction in IPCA between the periods in question.
Worthy of note is that in addition to the increase in interest on debt recorded in the result, there was a reduction of R$ 16 million (67.1%) in the capitalization of fixed assets due to the startup in operations at the Serra do Assuruá Wind Complex and the progress of the works on the Assú Sol Photovoltaic Complex.
Concession expenses payable (Use of a Public Asset): concession expenses payable fell by R$ 45 million (25.7%), and reaching R$ 130 million in 3Q25 as opposed to R$ 175 million in 3Q24 by virtue mainly of the decline of R$ 43 million of monetary restatement, in turn due largely a reflection of a reduction in IPCA and IGPM indices.
Income Tax and Social ContributionThe amount reported for Income Tax and Social Contribution (IR and CSLL) in 3Q25 was R$ 223 million, a variation of R$ 14 million (5.9%) when compared to R$ 237 million in the same quarter of 2024. The variation is mainly due to tax losses in certain consolidated companies. Excluding non-recurring effects resulting from the sales and acquisition of subsidiaries, income tax and social contribution expenses decreased by R$ 21 million (8.8%) between the quarters analyzed.
Adjusted net income in 3Q25 was R$ 731 million, R$ 65 million or 9.8% greater than R$ 666 million posted in the same quarter of 2024. The variation is the reflection of the following factors: (i) an increase of R$ 206 million in adjusted Ebitda; (ii) a reduction of R$ 21 million in income tax and social contribution, considering recurring transactions; partially offset by (iii) an increase of R$ 83 million in depreciation and amortization; and (iv) the negative effect of R$ 79 million for the net financial result.
Considering the non-recurring effects of the sale of a subsidiary, net income for 3Q25 was R$ 738 million, R$ 80 million or 12.2% greater than the R$ 658 million posted in the same quarter of the preceding year (considering the non-recurring effects of the costs of acquisition of subsidiaries and the sale of a stake in a jointly controlled subsidiary).
| Net Income Change | R$ million
21
+12.2%
+9.8%
(79)
206
(83)
731
738
658
666
7
8
30
Net income 3Q24
Non-recurring Adjusted net
income 3Q24
Adjusted Ebitda
Income Taxes
Financial result
Depreciation and amortization
Adjusted net Non-recurring
income 3Q25
Net income 3Q25
DebtAs of September 30, 2025, total consolidated gross debt, representing principally loans, financing, debentures and preferred shares redeemable, net of hedging operations, totaled R$ 29,668 million - an increase of 7.3% (R$ 2,008 million) compared to the position as of June 30, 2025. The average debt maturity at the end of the 3Q25 was 7.2 years.
The variation in Company's debt is mainly related to the combination of the following factors during the 3Q25: (i) R$ 2,130 million from the 15th debenture issuance; (ii) R$ 1,006 million in inflow of loans and debentures from acquired subsidiaries; (iii) generation of R$ 743 million in charges incurred to be paid and monetary restatement; and (iv) R$ 1,871 million in amortization of loans, financing, debentures, and preferred shares.
| Total Debt Change | R$ million
TJLP 6%
CDI
36%
IPCA 58%
+7.3%
2,130
27,660 1,006 743 -1,871
24,799
26,458
2,861
29,668
3,210
| Debt Breakdown
Total debt 6/30/2025
Debenture issuance
Loans and debentures of acquired subsidiaries
Charges
Amortization
Total debt 9/30/2025
Long term Short term