Engie Brasil Energia S.a.BMFBOVESPA: EGIE3

Earnings Release – 1Q26

May 7, 2026 at 11:40 PM UTC · Issued by Engie Brasil Energia S.a.

Watch Engie Brasil Energia explain itEngie Brasil Ene Sa S/Adr (EGIEY) Q1 2026 Earnings Call · Replay · May 8

EGIE3

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EGIEY

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ENGIE Brasil Energia S.A.

May 08, 2026 at 11:00 a.m. (BRT),

10:00 a.m. (EDT) in Portuguese with simultaneous translation into English)

Click here to access the transmission

Visit our Website

https://www.engie.com.br/investidores

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

ri.brenergia@engie.com

Florianópolis, Brazil, May 7, 2026. ENGIE Brasil Energia S.A. ("ENGIE" or "Company") - B3: EGIE3, ADR: EGIEY - announces earnings for the First Quarter and 3 months period ending on March 31, 2026 (1Q26/3M26). 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.

mark the 1Q26 of ENGIE Brasil Energia.

Asa Branca

Net Operating Revenue

R$ 3,409 million

(+13.1% vs 1Q25).

Adjusted Ebitda2

R$ 2,244 million

(+10.0% vs 1Q25).

Adjusted Net Income

R$ 789 million

(-4.1% vs 1Q25).

Average price of the energy sales agreements

R$ 216.8/MWh

net of taxes on revenues and trading operations

(+1.3% vs 1Q25).

Energy sales

10,592 GWh

(4,904 average MW) excluding trading operations (+10.5% vs 1Q25).

ENGIE sold 195.78 MW of power from Jaguara HPP at Aneel's Capacity Reserve Auction through the intermediary of a 15-year agreement, beginning August 2030 with a fixed annual revenue flow of R$ 270.4 million.

The Company made a successful bid for two lots in the Aneel transmission auction for the implementation of transmission lines and synchronous compensators, the respective concession being for 30 years at an annual RAP of R$ 122.8 million.

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.

Earnings Release 1Q26

Consolidated (in R$ million)	1Q26	1Q25	Var.
Net Operating Revenue (NOR)	3,409	3,013	13.1%
Results from Operations (EBIT)	1,865	1,722	8.3%
Ebitda 1	2,248	2,044	10.0%
Adjusted Ebitda 2	2,244	2,040	10.0%
Adjusted Ebitda by transmission and quota effects 3	2,089	1,804	15.8%
Ebitda / ROL - (%) 1	65.9	67.8	-1.9 p.p.
Adjusted Ebitda / ROL - (%) 2	65.8	67.7	-1.9 p.p.
Net Income	792	826	-4.1%
Adjusted Net Income	789	823	-4.1%
Adjusted Return on Equity (ROE) 4	19.0	25.8	-6.8 p.p.
Adjusted Return on Invested Capital (ROIC) 5	13.9	16.2	-2.3 p.p.
Net Debt 6	24,984	20,672	20.9%
Gross Power Generation (average MW) 7	5,840	5,389	8.4%
Energy Sold (average MW) 8	4,904	4,439	10.5%
Average Net Sales Price (R$/MWh) 9	216.76	213.98	1.3%
Number of Employees - Total	1,348	1,247	8.1%
Employees EBE	1,319	1,223	7.8%
Employees on under construction plants	29	24	20.8%

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.
ROIC: 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's Board of Directors approved the participation in the legal mechanism for renegotiating the Use of Public Assets (UBP) liabilities, enabling the anticipated payment of future obligations with respect to Cana Brava and Ponte de Pedra hydropower plants.

The Company celebrates its continuance in the Corporate Sustainability Index (ISE) for the 21st consecutive year, and in the Dow Jones Best-in-Class Emerging Markets index.

On April 16, the 2025 edition of ENGIE Brasil Energia's Sustainability Report was published. To access the full content, click here.

Approved by the Annual General Meeting held on April 24, 2026, the distribution of mandatory and complementary dividends for the fiscal year ending December 31, 2025, in the amount of R$ 557.8 million (R$ 0.4883/share), equivalent to 55% of the adjusted net profit for 2025. The shares are to trade ex-dividends as from May 5 and payout will take place on May 20, 2026.

With nearly thirty years of experience, attributes such as stability, flexibility, and a long-term vision were decisive in enabling ENGIE Brasil Energia in 2026 to continue creating value and promoting sustainable development. Amid a context of international pressures and economic and regulatory challenges, we have consistently advanced in the execution of our strategy, combining business expansion, financial strength, and the integration of environmental, social, and governance principles into our operations.

In the first quarter of 2026, we recorded a net operating revenue of R$ 3.4 billion, a growth of 13.1% compared to the same period in 2025. Adjusted Ebitda reached R$ 2.2 billion, an improvement of 10.0% relative to the first quarter of the preceding year, while adjusted net income amounted to R$ 789 million, 4.1% lower year-on-year. These numbers reflect the Company's solid progress, sustained by its operational and commercial performance during the period.

The 2025

Sustainability Report

is now available.

Access here.

Among the highlights of the quarter, we would focus the following:

Victory in the recent Transmission Auction, making the winning bid for lots 2 and 3, and in the Capacity Reserve Auction with the commercialization of 195.78 MW from the Jaguara Hydropower Plant, assuring the Company of significant and long-term revenues.
Continued implementation of the Asa Branca and Graúna transmission projects as well as the completion of the Assú Sol Photovoltaic Complex are reinforcing our participation in strategic transmission assets and renewable generation.
Continuing high levels of uptime in our generation and transmission assets, with particular reference to the hydropower plants (99.5%) and wind power farms (93.0%).

In the commercial area, we reported year-on-year growth of approximately 35% in the customer base and 29% in total consumer units, reflecting the consistence of our strategy and growth in demand for sustainable and longterm energy solutions.

As a highlight following the close of the first quarter, we published our 2025 Sustainability Report as well as recording our continued ranking in the Corporate Sustainability Index (ISE), for the 21st consecutive year, and in the Dow Jones Best-in-Class Emerging Markets, a demonstration of our commitment to ESG practices recognized internationally. In addition, the rating agency, Fitch Ratings, reiterated the Company's Long-Term National Rating at 'AAA(bra)' and on a global scale, the foreign currency denominated Long-Term IDRs (Issuer Default Ratings) as 'BB+' and in local currency, as 'BBB-', all with stable outlook. This again underscores ENGIE Brasil Energia's

position as a strong, reliable and resilient company, reflecting the consistent and robust performance of its strategy over the long- term.

We will remain focused on building a more dynamic, innovative, and competitive energy sector, capable of keeping pace with the evolving needs of Brazil. We recognize the fundamental role of our partners and collaborators who, at the beginning of 2026, worked to accelerate the transition towards a low-carbon energy matrix. Our priority is to expand the presence of renewable energy, ensuring that it is distributed safely, accessibly, and equitably, strengthening its positive impact on the country's economic and social development.

Good reading!

Eduardo Sattamini

Chief Executive Officer

Pierre Leblanc

Chief Financial and Investor Relations Officer

At the end of the 1Q26, ENGIE Brasil Energia had 11,265.9 MW of installed capacity and operates a generating complex with 12,965.6 MW, comprised of 145 plants (13 hydro and 132 complementary energy source plants - biomass, SHP, wind powered and solar), 142 of which are wholly-owned by the Company and three (the Itá, Machadinho and Estreito Hydropower Plants) jointly-owned through consortia with other companies.

Generating

Installed Capacity (MW) Authorization Commercial capacity

| Generating Complex as of March 31, 2026

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	May/42	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	Aug/37	127.6
Total - Hydro			8,739.9	7,040.2		3,576.6

Power Plants Source Location Company's (aMW) Company's Units1 Total expiration date Share Share
Serra do Assuruá Complex	Wind Farm	24	Lages and Pedro Avelino (RN)	846.0	846.0	Nov/56	410.2
Assu Sol Complex	Solar	16	Assú (RN)	752.7	752.7	Feb/57	229.6
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 Complex2	Solar	3	Pirapora (MG)	198.0	198.0	Apr/54	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 applicable3	0.2
Tubarão	Wind Farm		Tubarão (SC)	2.1	2.1	not applicable3	0.3
Tubarão 2	Wind Farm		Tubarão (SC)	4.2	4.2	not applicable3	0.0

Total - Complementary	4,225.6	4,225.6	1,799.9
Total	12,965.6	11,265.9	5,376.5

1 For the composition of wind and solar complexes.

2 The Lar do Sol plant does not have a declared physical guarantee, therefore its commercial capacity is based on expected generation.

3 For generating plants with installed capacity lower than or equal to 5 MW the legal instrument applicable is the record.

| Transmission Assets under Operation as of March 31, 2026

Transmission line	Location	Extention km	Annual RAP (R$ million) *	Substations	Property	Concession expiration
Gralha Azul	State of Paraná	909.0	341.1	5 own and expansion of 5 existing ones	100%	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
Asa Branca - Morro do Chapéu II - Poções III section	Bahia	334.0	91.3	Expansion of 2 related ones	100%	Sep/53
Total		3,205.0	917.2

* RAP: Annual Allowed Revenue. / Values on the base date of June 2025 (cycle 2025-2026), net of PIS and Cofins charges.

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 gas entry points (including 3 Liquified Natural Gas (LNG)), a further 90 gas outlet points and 2 bidirectional entry and outlet points, connection with 10 gas distributors, serving 2 refineries, 20 thermoelectric power plants and 2 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.

Following the expiry of the legacy Malha-NE contract in December 2025, TAG remains contracted for 77% of its capacity on the basis of long-term legacy agreements with Petrobras and for 23% through new contracts, covering the network's main delivery points. In the first quarter, 477 gas transportation contracts were signed, representing 67% of the total from the previous year and a 90% increase compared to the first quarter of 2025.

The regulator is currently undertaking a Tariff Review of TAG's Northeast Network (Malha-NE) section to determine the new Maximum Allowable Revenue (MAR), with completion of this exercise expected for mid-2026. The key decision taken during the period was the establishment of the WACC (Weighted Average Cost of Capital) at 7.63%. While the review process remains ongoing, firm annual agreements continue at unadjusted 2025 tariffs. However, the bidding processes for 2026 have already resulted in the signing of 73 contracts (47 in the 2025 process).

| Corporate Structure

LNG Terminal

Solimões

Basin

RN PB PE

Sergipe

Alagoas Basin

Recôncavo Basin

ENGIE S.A.

ENGIE Brasil Energia

Espírito Santo Basin

Campos Basin

Santos Basin

Currently, TAG has 29 firm capacity shippers, including producers, distributors, and a growing presence of traders and eligible consumers, confirming the dynamism of the natural gas market. Excluding Petrobras, the other shippers contracted an average of 11.5 million m³/day in the first quarter of 2026.

| Highlights of the quarter

In January, TAG began the daily execution of the Gas for System Use (GUS) Acquisition Processes across the Balancing Platform, thereby enhancing operational efficiency, transparency, and commitment to the market.
In March, the Capacity Reserve Auction in the form of Power (LRCAP) was held, in which 90 natural gas projects were selected, totaling 15.2 GW. Of these, 59 projects (7.7 GW) are located in the region served by TAG and in turn, 23 (2.2 GW) of their number have already signed a commitment agreement and expressed interest in connecting up to the grid, reinforcing the integration of thermal power plants in the system and at affordable tariffs.
Also in March, TAG began offering contracting windows for short-term products (Annual Flexible, Quarterly, Monthly, and Daily) simultaneously on all business days, increasing flexibility and simplifying operations for shippers.
| Projects:
TAG has a series of projects in hand to be executed over the next five years with planned investments of R$ 4.1 billion. 55% of this amount will be allocated in expansion projects, in line with the positive outlook of ENGIE Group for the natural gas industry in Brazil.
Completed:
Itagibá outlet point (BA): 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.
Under implementation:
Buriti outlet point (AM): implementation of a new outlet point, interconnecting the local distribution grid, with the purpose of supporting the expansion in thermoelectric demand in the Manaus region. The project's Construction Authorization was granted in July 2025, and conclusion of the work is expected for 2Q26.
Under development:
Suape entry point (PE): a new entry point to connect the LNG Terminal to the Port of Suape (Termopernambuco). The point will have a maximum transport capacity of 14.3 million m³/day and a length of 2 km, with the potential for expansion to 9 km.
Miranga entry point (BA): 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). The point will have a maximum transport capacity of 1.5 million m³/day and a length of 5 km.
Itajuípe compressor station (BA): located on the northern leg of the Gasene pipeline, with the objective of optimizing the network, the station will provide an incremental transport volume of 3 million m3/day. The project is listed in the New Growth Acceleration Program (PAC).
Connection of the Porto do Açú - GASOG (RJ): Goytacazes gas pipeline to connect the Porto do Açú regasification terminal to the Cabiúnas-Vitória gas pipeline, with 45 km of extension and 10 million m3/day of transportation capacity. The preliminary agreement for the design was approved at the end of 2022.

| Contracts Breakdown

Contract/Section	Extension (km)	Type	Customer	Contract Maturity	Capacity2 (MM m³/day)	Readjustment index
Gasene	1,400	Legacy	Petrobras	Nov-33	30.3	46% Basket IGP4; 54% US PPI
Urucu-Coari-Manaus	800	Legacy	Petrobras	Nov-30	6.7	50% IGP-M; 50% IPCA
Pilar-Ipojuca	200	Legacy	Petrobras	Nov-31	15.0	IGP-M
Malha Nordeste1	2,100	Not-Legacy	Varius	- -3 -
Lagoa Parda-Vitória1	100	Not-Legacy	Varius	Annual	0.3	55% IGP-M; 45% IPCA

Conexão GNL Sergipe1 25 Access

connection

Eneva Oct-54 14.0 20% IGP-M; 80% IPCA

Total ~4,600

1 Capacity contracted under the entry and exit regime through the Capacity Offer Portal (POC) .

2 Reference volume stipulated in the contract for ship-or-pay purposes. The actual contracted volume may vary in each period.

3 Volume to be defined in the tariff review process promoted by the ANP.

4 1/3 IGP-M, 1/3 IPA-DI; 1/3 IGP-DI.

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.

ENGIE Brasil Participações

Axia Energia

Mitsui & CO

On May 20, 2025, the Ministry of Mines and Energy (MME) issued Order N° 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 extended level and 2,335.1 average MW for operation at 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.

In 1Q26, Jirau Energia generated 2,998 average MW, 6.7% higher than the 2,809 average MW for 1Q25, 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 1Q26, the quota attributed to Brazil was 2,944 average MW, discounting the quota pertaining to the Bolivian government.

On December 12, 2025, ENGIE Brasil Energia's Board of Directors authorized the adoption of the necessary steps for the analysis and viability studies as an opening phase of discussions leading to the eventual transfer of ENGIE Brasil Participações' stake of 40% in Jirau Energia to the Company. The Special Independent Committee for Transactions with

| Jirau Energia PPA's Portfolio | Average MW

95 95 95 95

538

(29)

209

1,565

538

2,162

1,953

583

561

22 14

2,182 2,257 2,257 2,257 2,257 2,257

Related Parties has since been installed to advise on

2026-27 2028-34

2035

2036-42

2043

2044-45*

the analysis and to issue recommendations on possible structures for implementing the operation.

In addition, the Company's management hired financial advisory and is conducting, together with the

Regulated Partners Bilateral Uncontracted Losses

* Concession extension process through August 16, 2047 is under review by Aneel, in accordance with Memorandum No. 111/2026-SCE/Aneel.

Committee, studies and analyses regarding the most appropriate structure for the transfer to the Company of the shareholding interest in Jirau Energia.

Reserve Energy Auction - Jaguara Hydropower Plant

Jaguara HPP

In the Capacity Reserve Auction Number 2/2026 in the form of Power, the Company committed to sell 195.78 MW for a term of 15 years, delivery beginning on August 1, 2030. Fixed annual revenue is R$ 270.4 million (baseline September 2025), restated annually at the IPCA.

The expansion of installed capacity will be achieved by motorizing two existing turbine bays at the Jaguara Hydropower Plant, with the installation of two 116 MW turbines, totaling 232 MW. The estimated total investment is approximately R$ 1.2 billion (baseline March 2026).

Located on the Rio Grande River, on the Minas Gerais and São Paulo state divide, the Jaguara Hydropower Plant has 424 MW of installed capacity (324 average MW of commercial capacity), the current concession expiring June 2048. Currently, 70% of its commercial capacity is under a quota system while 30% is allocated to the Free Contracting Environment (ACL).

Colibri Transmission System - Paraná, Santa Catarina, Ceará and Rio Grande do Norte

Following a successful bid in Aneel's Transmission Auction 01/2026, Lots 2 and 3 were nominated Colibri Sul and Colibri A, B, C and D, respectively, and have the

Lot 3

following characteristics:

Lot 2 - Colibri Sul - construction of a transmission line of 230 kV of approximately 143 kilometers in the states of Paraná and Santa Catarina. The project enjoys local and operational synergies with both Gralha Azul (already operating) and Graúna (in the process of implementation) systems. The contracted RAP for this stretch is R$ 18.1 million and an investment of the order of R$ 193.6 million.
Lot 3 - Colibri A, B, C and D - divided in sublots 3A, 3B, 3C and 3D, involves the installation of five synchronous compensators in the states of Ceará and Rio Grande do Norte, where the Company already has generation assets, so enhancing operational efficiency and synergy. At an estimated investment of R$ 1.4 billion, the

CE RN

contracted RAP for the lot is R$ 104.7 million.

The term of the public transmission service concession, including licensing, construction, operation, and maintenance of transmission facilities, is 30 years, effective from the date the concession agreement is signed. The deadline for commencing operations is December 2029.

Lot 2

Block Location Contracted RAP (R$ million)

Estimated Aneel Capex (R$ million)

	2	Paraná and Santa Catarina	18.1	193.6
	3	Ceará and Rio Grande do Norte	104.7	1,381.1
Total			122.8	1,574.7

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 November 26, 2025, the 334-kilometer 500kV Morro do Chapéu II - Poções III section was energized, representing 32.3% of total RAP.

On February 6, 2026, Ibama issued the Installation License specifically for the construction and operation of all transmission lines, as well as the Medeiros Neto II Substation. Additionally, in 1Q26, a new request for the full Installation License was filed with this same federal organ which remains under review.

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

Total 282.7 2,667.0

1 Value as of June 2025.

Towers assembling

Section operational

Graúna

Transmission assets

(Gralha Azul and Asa Branca)

Graúna greenfield lot -under implementation

Graúna brownfield lot -operational (5% of RAP)

Generation assets under operation

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 operation of existing assets (brownfield), totaling 162 kilometers of transmission lines and two substations in the states of Minas

Gerais and Espírito Santo.

The transmission line concession will be 30 years from the signature date of the concession agreement, which occurred on December 9, 2024.

On July 18, 2025, the Company assumed the operation of the brownfield section, whose Annual Permitted Revenue (RAP) is R$ 14.0 million, equivalent to approximately 5% of the project total.

In 1Q26, the project showed progress in its main implementation pillars, notably the holding of public hearings on the section under licensing by the environmental agency of

the State of Santa Catarina, in addition to advances in environmental licensing and land ownership title. Pre-construction activities and engineering development also continued, including technical solutions aimed at

environmental optimization of the route. The project schedule remains on track, without significant impacts on key milestones.

The maximum permitted term for construction is 60 months (December 2029), albeit with the possibility of abbreviating the period. The project enjoys synergies with other assets in the Company's portfolio, favoring operational and strategic gains.

Block

Location

Contracted RAP Estimated Aneel Capex

(R$ million)1

(R$ million)

Santa Catarina, Paraná, Minas Gerais, São Paulo and Espírito Santo

268.3 2,933.6

Total 268.3 2,933.6

1 Value as of June 2025.

Projects under development are in the pipeline and at a feasibility studies stage, and awaiting adequate commercial conditions and evidence of future pricing for investments.

Installed Capacity (MW) Plants Source Location Total Company's Share
Santo Agostinho Solar Complex	Solar	Lajes and Pedro Avelino (RN)	509.0	509.0
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			1,388.0	1,388.0

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.

In 1Q26, the hydropower plants operated by ENGIE Brasil Energia, recorded an internal uptime rate of 99.5%, (taking into account forced and programmed stoppages). This rate represented an increase of 2.9 p.p. in 1Q26 compared to the same period in 2025 (96.6%), largely due to significantly higher uptime in the quarter at Salto Osório Hydropower Plant, where in 1Q25, the Number 2 Generator Unit was still in the process of modernization.

As to the wind plants, the 1Q26 internal energy up-time rate was 93.0%, 1.3 p.p. greater than the 91.7% in 1Q25. This improvement reflects the start in commercial operations of the Serra do Assuruá Wind Complex, the

| Uptime Operating | Considering Scheduled and Forced Shutdowns

+2.9 p.p.

-0.2 p.p.

96.6% 99.5%

91.7% 93.0%

93.8% 95.6%

+1.3 p.p.

+1.8 p.p.

99.98%99.78%

integration of which into the Company's portfolio was concluded in the second half of 2025 with positive results being recorded since the first months of operations.

Hydro

Wind

Photovoltaic

1Q25 1Q26

Transmission

Improved operational efficiency was also driven by uptime gains at the Santo Agostinho Wind Complex, where in the first quarter of 2025 there had been prolonged down time at some wind turbines for blade inspection.

The Company's photovoltaic plants posted 95.6% uptime in 1Q26, 1.8 p.p. superior to 93.8% in 1Q25. The improvement is the result of implementation of a recovery plan for the photovoltaic plants nationwide. This included several initiatives taken during 2025 such as modernization of trackers, preventive maintenance work on inverters, refurbishing of PV strings and improvements in medium voltage network cables.

In the case of the transmission assets Gralha Azul, Novo Estado, Gavião Real, Graúna and Asa Branca, ENGIE Brasil Energia continues to register high operational performance with a total uptime rate of 99.78% in 1Q26. The slightly lower value compared to the same period of the previous year, in which total availability was 99.98%, occurred mainly due to a one-off event on the Serra Pelada Miracema transmission line. However, since the start of commercial operations, the Company's transmission assets have recorded a high degree of operational excellence.

Plants operated by ENGIE Brasil Energia in 1Q26 generated 12,614 GWh

(5.840 average MW), 8.4% more than 1Q25.

Out of the total generated, the hydropower plants accounted for 10,332 GWh (4,784 average MW) while complementary power plants responded for 2,281 GWh (1,056 average MW). These results represent increases of 8.7% in generation from hydro and 6.7% in complementary power plants, compared to 1Q25.

The year-on-year increase in generation from the hydropower plants in 1Q26 is directly related to operational factors. The operational policy of the National Interconnected System (SIN) defines the allocation of hydroelectric generation, prioritizing medium- and high-load levels to meet demand.

In the case of the Tocantins river basin, hydrological conditions were relatively favorable during the rainy season. However, the first quarter of 2026 recorded greater variability with intense but sporadic periods of rainfall, distributed irregularly over the period, insufficient to be deemed a consistent hydrological pattern.

The increase in generation from the complementary plants in 1Q26 compared to 1Q25 was driven by the conclusion of entry into operation of the Assú Sol Photovoltaic Complex. In the quarter, the asset reported generation of 393 GWh (182 average MW), contributing to growth of 47.0% in solar generation as a whole in relation to the same quarter in 2025, totaling 745 GWh (345 average MW). In compensation, wind generation amounted to 1,492 GWh (691 average MW), representing a reduction of 5.3% in relation to 1Q25, a reflection of lower than expected winds in the Campo Largo, Umburanas and Santo Agostinho wind complexes areas.

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 | Avg MW

+8.4%

5,840

4,400

4,784

989

1,056

5,389

1Q25 1Q26

Hydro

Complementary

| Generation by Complementary Source | Avg MW

+6.7%

1,056

691

729

236

234

109

989

1Q25 1Q26

Wind Solar New solar SHP Biomass

According 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). Law 15,269, promulgated in November 2025, establishes a compensation system for generation cuts in the case of Electrical Reliability and External Unavailability as from September 01, 2023 to November 2025, based on the regulations of the Law.

According to the analysis of data released by the ONS, in 1Q26, wind and solar power plants operated by ENGIE Brasil Energia recorded generation curtailment of 17%, a level in line with that observed for the group of power plants that make up the National Interconnected System (SIN). The Company's wind power plants recorded a 17% reduction in generation, slightly lower than the 19% posted for the SIN, while solar plants registered curtailment of 17%, slightly higher than the 15% observed for the SIN, as shown in the table below:

\| % Curtailment by source
		1Q26			1Q25
	Wind	Solar	Total	Wind	Solar	Total
Curtailment ENGIE Brasil Energia	17%	17%	17%	20%	19%	20%
Curtailment SIN	15%	19%	17%	14%	21%	16%

| % Curtailment by asset

Wind power plants	Commercial capacity (avgMW)	1Q26 (%)	1Q25 (%)
Trairi (CE)	97.2	25%	30%
Santo Agostinho (RN)	224.2	21%	8%
Serra do Assuruá (BA)	846.0	20%	21%
Campo Largo I e II (BA)	359.0	9%	21%
Umburanas (BA)	213.3	15%	26%

Solar power plants

Commercial capacity (avgMW)

1Q26 (%)

1Q25 (%)

Sol do Futuro (CE) 16.2 20% 26%

Assú Sol (RN) 229.6 13% 12%

Floresta (RN) 25.1 18% 22%

| % Curtailment over 1Q26 Generation | Average MW

1,250

214

(17%)

1,035

5,840

(4%)

214

6,054

Assú V (RN)	9.2	19%	15%	Wind + solar	Total
Juazeiro (BA)	34.8	14%	34%	generation	generation
Sertão Solar (BA)	26.1	31%	19%	Generation	Curtailment
São Pedro (BA)	16.0	47%	50%
Lar do Sol (MG)	53.0	17%	15%
Paracatu (MG)	34.0	17%	10%

Source: In-house study by ENGIE Brasil Energia based on assumptions published by the ONS and subject to updates.

We 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.

| Breakdown of Customers by Physical Sales (%)

36.8

41.3

53.8

59.2

4.0

4.9

| Breakdown of Customers in Contracted Sales Comprising NOR of the Generation Segment (%)

52.5

52.0

42.6

2.2

45.8

4.9

1Q25 1Q26 1Q25 1Q26

Distribution Companies Free Customers and Trading Companies Trading Operations

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 March 31, 2026, is as follows:

| Energy Balance

(in average MW)	2026	2027	2028	2029	2030	2031	In R$/MWh
Own Resources	5,171	5,186	5,183	5,182	5,150	4,262	Auction Gross Price	Reference Date	Adjusted Gross Price	Price Net of PIS/ Cofins/P&D
+ Purchases for Resale	704	436	377	231	205	156
= Total Resources (A)	5,875	5,622	5,560	5,413	5,355	4,418
Government Auction Sales1	2,178	2,338	2,414	2,230	2,144	2,144
2005-NE-2010-30	200	200	200	200	200	200	115.1	Dec-05	331.9	298.2
2006-NE-2009-30	493	493	493	493	493	493	128.4	Jun-06	364.2	327.2
2006-NE-2011-30	148	148	148	148	148	148	135.0	Nov-06	380.4	341.8
2007-NE-2012-30	256	256	256	256	256	256	126.6	Oct-07	342.5	307.7
Proinfa	19	10	-	-	-	-	147.8	Jun-04	472.0	454.8
2014-NE-2019-25	10	10	10	10	10	10	206.2	Nov-14	378.9	365.1
2014-NE-2019-20	82	82	82	82	82	82	139.3	Nov-14	256.0	232.3
2015-NE-2018-20	46	46	46	46	46	46	188.5	Aug-15	321.0	291.3
8th Reserve Energy Auction (Assú V/Floresta/ Paracatu/Juazeiro/Sol do Futuro)	119	119	119	119	119	119	298.2	Nov-15	493.5	447.9
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	256.5	232.8
2017-EN-2021-20 (Sertão Solar)	27	27	27	27	27	27	189.5	Nov-14	218.1	197.9
2024-EE-2025-2	15	-	-	-	-	-	162.6	-	162.6	147.6
2012-EN-2017-30	151	151	151	151	151	151	95.3	Dec-12	192.1	174.3
2010-EN-2015-30	190	190	190	190	190	190	104.0	Dec-10	241.3	219.0
2025-EE-2027-3	-	184	270	86	-	-	207.7	Nov-25	207.7	188.5
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
+ Bilateral Sales	2,960	2,464	1,921	1,122	956	649

= Total Sales (B)	5,138	4,802	4,335	3,352	3,100	2,793
- Commercial hedge	572	572	572	572	572	572
Balance (A - B)	165	248	653	1,489	1,683	1,053
Sales average net price (R$/MWh) 2, 3:	225.4	228.5	235.1
Purchases average net price (R$/MWh) 4:	190.1	180.0	167.3

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.

| Results by segment - 1Q26 X 1Q25 | R$ million

Electric energy

Generation¹ Transmission Trading Gas Consolidated

transportation

1Q26

Net operating revenue	2,746	542	121	-	3,409
Operational costs	(1,238)	(219)	(119)	-	(1,576)
Gross income	1,508	323	2	-	1,833
Selling, general and administrative expenses	(97)	(5)	(2)	-	(104)
Other operating expenses, net	(2)	-	-	-	(2)
Disposal of subsidiary	4	-	-	-	4
Equity income	-	-	-	133	133
Income (loss) before financial results and taxes	1,413	318	-	133	1,864
1Q25
Net operating revenue	2,275	691	47	-	3,013
Operational costs	(984)	(342)	(46)	-	(1,372)
Gross income (loss)	1,291	349	1	-	1,641
Selling, general and administrative expenses	(94)	(4)	(2)	-	(100)
Other operating revenues, net	10	-	-	-	10
Disposal of subsidiary	4	-	-	-	4
Equity income	-	-	-	167	167
Income (loss) before financial results and taxes	1,211	345	(1)	167	1,722
Change
Net operating revenue	471	(149)	74	-	396
Operational costs	(254)	123	(73)	-	(204)
Gross income	217	(26)	1	-	192
Selling, general and administrative expenses	(3)	(1)	-	-	(4)
Other operating expenses, net	(12)	-	-	-	(12)
Equity income	-	-	-	(34)	(34)
Income (loss) before financial results and taxes	202	(27)	1	(34)	142

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.

| Operating revenue by segment - 1Q26 X 1Q25 | R$ million

	Electric Energy
	Generation Transmission Trading Consolidated
1Q26

Regulated contracting environment1	1,200	-	-	1,200
Free contracting environment2	1,096	-	-	1,096
Remuneration of concession assets	134	312	-	446
Transactions in the short-term energy market	239	-	-	239
Construction revenue	-	207	-	207
Energy trading operations	-	-	119	119
Service rendered revenue	42	21	-	63
Indemnifications	11	2	-	13
Unrealized gains on trading operations	-	-	2	2
Other revenues	24	-	-	24
Net operating revenue	2,746	542	121	3,409
	1Q25
Regulated contracting environment	1,092	-	-	1,092
Free contracting environment	960	-	-	960
Remuneration of concession assets	151	310	-	461
Transactions in the short-term energy market	23	-	-	23
Construction revenue	-	355	-	355
Energy trading operations	-	-	47	47
Service rendered revenue	38	26	-	64
Other revenues	11	-	-	11
Net operating revenue	2,275	691	47	3,013
	Change
Regulated contracting environment	108	-	-	108
Free contracting environment	136	-	-	136
Remuneration of concession assets	(17)	2	-	(15)
Transactions in the short-term energy market	216	-	-	216
Construction revenue	-	(148)	-	(148)
Energy trading operations	-	-	72	72
Service rendered revenue	4	(5)	-	(1)
Indemnifications	11	2	-	13
Unrealized gains on trading operations	-	-	2	2
Other revenues	13	-	-	13
Net operating revenue	471	(149)	74	396

1 Distribution companies.

2 Free consumers and trading companies.

In 1Q26, net operating revenue increased 13.1% (R$ 396 million) when compared to 1Q25, from R$ 3,013 million to R$ 3,409 million. This variation arises largely from the following effects: (i) growth of R$ 471 million (20.7%) in net operating revenue from the portfolio's energy generation and sales segment; (ii) elevation of R$ 74 million (157.4%) in the trading segment; and attenuated by (iii) a reduction of R$ 149 million (21.6%), in the transmission segment. More details on the transmission and trading segments are described below under specific headings.

| Net Operating Revenue Change by Segment | R$ million

3,409

121

(4%)

(2%)

2,275

(76%)

2,746

(81%)

+13.1%

542

(16%)

691

(23%)

244

216

(149)

3,013

NOR 1Q25

Price and sales volume

CCEE Others Trading

Transmission

NOR 1Q26

Generation and portfolio sale Trading Transmission

Net Average Selling Price and Sales Volume

The average selling price of energy, net of charges on revenue and trading operations, was R$ 216.76/MWh in 1Q26. This amount was 1.3% higher in relation to 1Q25, when selling prices posted an average of R$ 213.98/MWh.

During both 2025 and 2026, trading conditions were characterized by reimbursement for shortfalls in wind and solar energy deliveries below contractual commitments agreed with distribution companies for contracts in the regulated environment. Ignoring the impact of reimbursements in the quarters under review, the net average selling price increased from R$ 218.44/MWh in 1Q25, to R$ 219.78/MWh in 1Q26, a growth of 0.6%.

The increase in price between the comparable periods in question was largely a reflection of: (i) rising market prices throughout 2025 and 2026, which positively impacted free market conditions for 2026; (ii) monetary restatement applied to current long-term supply agreements; and partially offset by (iii) the inclusion of contracts inherited from the acquisition of the Santo Antônio do Jari and Cachoeira Caldeirão hydropower plants.

Energy volumes sold under agreements, net of trading operations, increased from 9,588 GWh (4,439 average MW) in 1Q25 to 10,592 GWh (4,904 average MW) in 1Q26, a growth of 1,004 GWh (465 average MW), or 10.5%, between the periods under review.

The increase in energy volumes sold during the quarter was largely a reflection of additional amounts commercialized to distribution companies in the quarter following the acquisition of the Santo Antônio do Jari and Cachoeira Caldeirão hydropower plants and the increase in sales in the free market environment in the light of an increase in proprietary installed capacity between the periods, due to completion of entry into commercial operations of the Serra do Assuruá Wind Complex in the second half of 2025 and the Assú Sol Photovoltaic Complex in 1Q26.

Variations in sales volumes and in average selling prices combined contributed to an increase of R$ 244 million in the Company's net operating revenue during the quarter.

| Net Average Selling Price1

| R$/MWh

+1.3%

214.0 216.8

1Q25 1Q26

| Sales Volume2 | avg MW

+10.5%

4,439

4,904

1Q25 1Q26

1 Net of sale taxes and trading operations.

2 Net of trading operations.

Energy Transactions

Revenues from sales to distribution companies totaled R$ 1,200 million in 1Q26, R$ 108 million (9.9%) greater than the R$ 1,092 million verified in 1Q25. This positive variation was mainly due to a combination of the following effects: (i) R$ 138 million due to the growth of 478 GWh (221 average MW) in volume sold; and (ii) a reduction in R$ 30 million with the decrease of 2.7% in the net average selling price.

The year-on-year increase in sales volume reported for 1Q26 was mainly due to energy commercialized by the hydropower plants acquired in 3Q25, Santo Antônio do Jari and Cachoeira Caldeirão and in the light of the Company's seasonalizing of sales. The reduction in net average sales price between quarters analyzed was mainly due to: (i) the incorporation of agreements related to the acquisition of the Santo Antônio do Jari and Cachoeira Caldeirão hydropower plants; and offset: (ii) by the monetary restatement of sale prices in the periods under comparison.

Disregarding the impact of the reimbursements cited above, net average sales price to distribution companies decreased by 8.3% between quarters.

Sales revenue to free consumers and trading companies increased R$ 136 million (14.2%) between the quarters analyzed from R$ 960 million in 1Q25 to R$ 1,096 million in 1Q26. The variation is the result of the increase of 4.8% in net average selling price (R$ 46 million) and the increase of 526 GWh (244 average MW) in energy sales volume (R$ 90 million).

The variation in energy volumes sold is due principally to the startup of operations at the Serra do Assuruá Wind Complex and Assú Sol Photovoltaic Complex, and a reflection of the larger amounts of energy available in the Company's portfolio. Conversely, the increase in net average selling price was driven largely by (i) higher market prices throughout 2025 and 2026, which positively impacted free market conditions for 2026, as explained previously; and (ii) monetary restatement of existing long term agreements.

Concession Assets Remuneration

The financial assets of concessions represent the present value of future cash flows from the portion of energy sold to the Regulated Contracting Environment (ACR) from the Jaguara and Miranda hydropower plants and equivalent to 70% of the physical guarantee of both plants. These assets are remunerated at the annual internal rate of return and restated according to the variation in the Amplified Consumer Price Index (IPCA).

The remuneration of the financial assets of concessions fell from R$ 151 million in 1Q25 to R$ 134 million in 1Q26, a reduction of R$ 17 million (11.3%). This variation was substantially due to the reduction in IPCA between the consecutive first quarters under review.

Transactions in the Short-term Energy Market

In 1Q26, revenue from the short-term market totaled R$ 239 million compared to R$ 23 million in 1Q25, representing an increase of R$ 216 million between the compared quarters. Further details regarding these transactions and variation can be found in "Details of short-term operations".

| Costs by segment - 1Q26 x 1Q25 | R$ million

	Electric Energy
	Generation Transmission Trading Consolidated
1Q26

Depreciation and amortization	372	3	-	375
Electric power purchases	229	-	119	348
Charges for the use of power grid and connection	217	-	-	217
Construction costs	-	194	-	194
Materials and third-party services	122	10	-	132
Transactions in the short-term market	107	-	-	107
Personnel	77	6	-	83
Royalties	58	-	-	58
Insurance	49	1	-	50
Other operational costs, net	7	5	-	12
Operational costs	1,238	219	119	1,576
1Q25
Depreciation and amortization	309	3	-	312
Electric power purchases	139	-	45	184
Charges for the use of power grid and connection	190	-	-	190
Construction costs	-	325	-	325
Materials and third-party services	111	8	-	119
Transactions in the short-term market	49	-	-	49
Personnel	61	2	-	63
Royalties	53	-	-	53
Insurance	34	-	-	34
Unrealized losses on trading operations	-	-	1	1
Other operational costs, net	38	4	-	42
Operational costs	984	342	46	1,372
	Change
Depreciation and amortization	63	-	-	63
Electric power purchases	90	-	74	164
Charges for the use of power grid and connection	27	-	-	27
Construction costs	-	(131)	-	(131)
Materials and third-party services	11	2	-	13
Transactions in the short-term market	58	-	-	58
Personnel	16	4	-	20
Royalties	5	-	-	5
Insurance	15	1	-	16
Unrealized losses on trading operations	-	-	(1)	(1)
Other operational costs, net	(31)	1	-	(30)
Operational costs	254	(123)	73	204

Operational costs increased R$ 204 million (14.9%) between quarters from R$ 1,372 million in 1Q25 to R$ 1,576 million in 1Q26, a reflection mainly of the combination of the following factors: (i) an increase of R$ 254 million (25.8%) in costs of energy generation and sales from the Company's portfolio segment; (ii) an increase of R$ 73 million (158.7%) in the costs of energy trading operations; and (iii) a decline of R$ 123 million (36.0%) in costs of the transmission segment.

| Operational Costs Change | R$ million

164

1,576

119

5 (1) 6

(131)

1,372

+14.9%

342

984

1,238

(79%)

219 (8%)

14%)

(

Cost 1Q25	Depreciation	Purchases for	CCEE	Charges for	Materials and	Construction	Other	Cost 1Q26
	and	portfolio		power grid and	third-party	costs
	amortization			connection	services

Generation and portfolio sales 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:

Depreciation and amortization: increase of R$ 63 million (20.4%), between quarters analyzed. The variation stems largely from: (i) the startup in commercial operations of the Serra do Assuruá Wind Complex and the Assú Sol Photovoltaic Complex, completed during 2025 and 1Q26, respectively; and (ii) greater depreciation reported from the recently acquired Santo Antônio do Jari and Cachoeira Caldeirão subsidiaries.
Energy purchases: between 1Q25 and 1Q26 the Company posted an increase of R$ 90 million (64.7%) in energy purchases, substantially due to the combination of a growth of 644 GWh (298 average MW) in the energy volume purchased (R$ 75 million) and the increase of 7.6% in the net average energy purchase price (R$ 15 million). Volume growth is due to the increase in purchases for the purpose of the Company's portfolio management. Additionally, the variation in the average purchase price reflects the increase in month-end closing prices due to the rise in the average PLD between the compared quarters and the monetary restatement of long-term contracts.
Charges for use of the network and connection: an increase of R$ 27 million (14.2%) between the quarters under review and resulting largely from: (i) the startup in commercial operations 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 readjustment in transmission and distribution tariffs.
Material and third-party services: an increase of R$ 11 million (9.9%) between the quarters under analysis. The leading drivers were the result of the following factors: (i) the startup in commercial operations at the Serra do Assuruá Wind Complex and Assú Sol Photovoltaic Complex; (ii) the acquisition of the Santo Antônio do Jari and Cachoeira Caldeirão subsidiaries; and (iii) the provision of consultancy and advisory services.
Transactions in short-term energy market: costs of these transactions rose by R$ 58 million (118.4%) between the successive first quarters. Further explanation on these operations and with respect to the variation can be found under "Details of short-term operations".

Other costs related to this segment revealed no significant variations between the quarters under analysis.

Asa Branca

The 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 operations on February 19 and 27, 2023, respectively. On July 8, 2024, the Company finalized the implementation of the

Gavião Real Transmissora de Energia project with its complete energization as incorporated in the Delivery and Acceptance Certificate (TLD) issued by the National System Operator (ONS) on July 12, 2024. 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. Additionally, on November 26, 2025, the Company received authorization from the ONS to begin commercial operations on the Morro do Chapéu II - Poções III stretch pertaining to the Asa Branca Transmission System and representing 33% of the project's RAP.

The gross result from the energy transmission segment reached a positive R$ 323 million in 1Q26, a reduction of R$ 26 million (7.4%) compared to the same quarter in 2025, when this item reported R$ 349 million. The variation is a reflection of: (i) the negative impact of R$ 17 million (5.5%) in variation of the net amount of construction costs and revenues (a reduction of R$ 148 million and R$ 131 million, respectively), stemming mainly from the stage of the work schedule at the Asa Branca Transmission System; (ii) the increase of R$ 8 million in costs and a reduction of R$ 5 million in O&M revenue respectively, resulting in an overall negative impact of R$ 13 million; and (ii) offset by a growth of R$ 2 million (0.6%) in the remuneration of concession assets due more particularly to the greater nominal balance and by a reduction in inflation rates between compared quarters.

The RAP value, net of PIS and Cofins, received in 1Q26 was R$ 225 million, (R$ 186 million in 1Q25), being R$ 204 million (R$ 160 million in 1Q25) corresponding to the amortization of the contractual asset registered as a contra-entry to the contractual asset, and R$ 21 million (R$ 26 million in 1Q25) relative to revenue for services rendered by O&M.

Below is the composition of the regulatory transmission Ebitda:

(in R$ million)	1Q26	1Q25	Change
RAP, net of PIS and Cofins	225	186	39
Operational costs	(22)	(14)	(8)
Selling, general and administrative expenses	(5)	(4)	(1)
Other operational revenues, net	2	-	2
Regulatory transmission Ebitda	200	168	32

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.

A comparison of the gross result of the quarters under analysis reported a positive variation of R$ 1 million, a reflection of the increase of R$ 3 million following marketing-to-market of forward supply transactions, quarter x quarter - the difference between contract prices and market prices, offset by the negative impact of R$ 2 million from short-term transactions.

Short-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.

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

	1Q26
Net operating revenue		239
Operational costs		(107)
Net result		132
	1Q25
Net operating revenue		23
Operational costs		(49)
Net result		(26)
	Change
Net operating revenue		216
Operational costs		(58)
Net result		158

In 1Q26 and 1Q25, net results (difference between revenue and costs - less taxes) from short-term operations

- more especially those contracted across the CCEE - were positive at R$ 132 million and a negative R$ 26 million, respectively. The result for the first quarter of 2026 represents an increase of R$ 158 million compared with 1Q25 reflecting transactions conducted in the energy generation and sales from the portfolio segment.

These variations were primarily the result of a combination of the following factors: (i) an increase in free energy due to the seasonal energy allocation strategy implemented over the course of the periods, combined with an increase in PLD; (ii) the positive effect on the MRE, due to higher hydroelectric generation than in the previous year and the consequent increase in the amount to be reimbursed by the other MRE participants; mitigated (iii) by the negative impact resulting from the reduction in the MRE Adjustment Factor (GSF), given the allocation of physical guarantee and the generation of participating plants (the average GSF grew from 107.7% in 1Q25 to 92.0% in 1Q26); and (iv) the effects of the negative variation in month-end closing operations, rebooking, and adjustments between the quarters analyzed.

In December 2025, Aneel established maximum and minimum PLD limits for 2026 at R$ 785.24/MWh and R$ 57.31/MWh, respectively. The following table shows average PLD values for the submarkets in which the Company operates, in MWh.

Average PLD in R$/MWh	1Q26	1Q25	Change
South	359.40	161.87	122.0%
Southeast/Center-West	310.54	160.10	94.0%
Northeast	289.80	58.91	391.9%

The Company reported an increase in sales, general and administrative expenses in the amount of R$ 4 million (4.0%) between 1Q26 and 1Q25. Variation between the quarters analyzed largely reflect the increase in the generation segment of R$ 3 million, mainly impacted by the increase in labor overheads due to the annual adjustment in employee remuneration and benefits, as well as new hirings between the two quarters.

The 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:

1Q26 1Q25

Income statement (in R$ million)

100%

Company's

100%

Company's

Net operational revenue 2,074 363

Costs of services provided (611) (107)

Gross income 1,463 256

General and administrative expenses (69) (12)

Income before financial result and taxes 1,394 244

Financial result (451) (79)

Income before taxes 943 165

Income tax and social contribution (180) (32)

2,340 410

(606) (106)

1,734 304

(43) (8)

1,691 296

(494) (86)

1,197 210

(244) (43)

TAG's net income

763

133

953

167

The reconciliation of TAG's Ebitda is shown in the following table:

1Q26 1Q25

Ebitda (in R$ million)	100%	Company's share	100%	Company's share
Income before financial result and taxes	1,394	244	1,691	296
Depreciation and amortization	179	31	184	32
Amortization of mais valia	150	26	150	26
Ebitda¹	1,723	301	2,025	354

Ebitda Margin 83.1% 86.5%

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 1Q25 and 1Q26, equity income declined by R$ 34 million (20.4%) from R$ 167 million to R$ 133 million respectively. This variation was a reflection of the decrease in net income reported by TAG.

With regard to the decline in TAG's earnings, the change was primarily due to: (i) reduced revenue in the case of the Malha Nordeste (the Northeast Network), resulting from the lack of definition of the maximum permitted revenue (to be recalculated after the tariff review is approved); (ii) lower tariff increases with adjustments linked to the dollar and inflation; mitigated by (iii) the decrease in financial result; (iii.i) the decline in interest on debt; and (iii.ii) partially offset by the decline in interest income on investments; and (iv) the decrease in income tax (IR) and social contribution (CSLL) due to the recognition of deferred income tax and social contribution on regulatory provisions.

| Balance Sheet

Transportadora Associada de Gás - TAG

TAG's principal asset and liability groups as of March 31, 2026 and December 31, 2025 were as follows:

Balance Sheet	03/31/2026	12/31/2025
ASSETS
Current assets	3,295	2,530
Cash and cash equivalents	1,875	655
Accounts receivable from clients	1,281	1,706
Other current assets	139	169
Non-current assets	28,350	28,269
Restricted deposits	786	460
Other non-current assets	157	162
Property, plant and equipment	24,652	24,892
Intangible	2,755	2,755
Total	31,645	30,799
LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities	3,083	2,888
Debt instruments	1,913	2,004
Derivative financial instruments - hedge	48	73
Other current liabilities	1,122	811
Non-current liabilities	21,404	21,844
Debt instruments	14,476	14,936
Derivative financial instruments - hedge	153	210
Deferred income taxes and social contribution	6,155	5,933
Other non-current liabilities	620	765
Shareholders' equity	7,158	6,067
Total	31,645	30,799

| Ebitda by segment - 1Q26 x 1Q25 | R$ million

Electric Energy

Generation Transmission Trading Gas Consolidated

Transportation

1Q26

Income (loss) before financial results and taxes	1,413	318	- 133		1,864
Depreciation and amortization	381	3	- -		384
Ebitda1	1,794	321	- 133		2,248
Disposal of subsidiary	(4)	-	- -		(4)
Adjusted Ebitda	1,790	321	- 133		2,244
Adjusted Ebitda margin	65.2%	59.2%	- -		65.8%
	1Q25
Income (loss) before financial results and taxes	1,211	345	(1)	167	1,722
Depreciation and amortization	319	3	-	-	322
Ebitda	1,530	348	(1)	167	2,044
Disposal of subsidiary	(4)	-	-	-	(4)
Adjusted Ebitda	1,526	348	(1)	167	2,040
Adjusted Ebitda margin	67.1%	50.4%	(2.1%)	-	67.7%
Change
Income (loss) before financial results and taxes	202	(27)	1	(34)	142
Depreciation and amortization	62	-	-	-	62
Ebitda	264	(27)	1	(34)	204
Adjusted Ebitda	264	(27)	1	(34)	204
Adjusted Ebitda margin	(1.9 p.p.)	8.8 p.p.	2.1 p.p.	-	(1.9 p.p.)

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 1Q26 and 1Q25, Adjusted Ebitda increased R$ 204 million (10.0%) from R$ 2,040 million in 1Q25 to R$ 2,244 million in 1Q26. The variation was the result of the positive effects of: (i) R$ 264 million (17.3%) in the energy generation and sales from the Company's portfolio segment; and (ii) R$ 1 million (100.0%), the result of the energy trading segment. These effects were attenuated by the negative effects of (i) R$ 34 million (20.4%) due to the lower result from a stake in the jointly held subsidiary - TAG; and (ii) R$ 27 million (7.8%) reduction in the results from the energy transmission segment.

The main variations in Adjusted Ebitda are in the electric energy generation and sales segment, as indicated in item (i) above, positive effects of which were: (i) R$ 244 million from the combination of variations in the volume of electricity sold and the average net selling price; (ii) R$ 158 million from the positive impact of transactions in the short-term market; and (iii) R$ 7 million related to other operating costs and administrative expenses. These effects were offset by the following negative aspects: (iv) an increase of R$ 90 million in energy purchases; (v) an increase of R$ 27 million for use of the electricity grid and connection charges; (vi) a decrease of R$ 17 million in income from financial assets of concessions; and

(vii) an increase of R$ 11 million in costs of materials and third-party services.

| Adjusted1 Ebitda | R$ million

67.7%

65.8%

2,248

2,044

+10.0%

2,244

2,040

1Q25 1Q26

Adjusted Ebitda Non recurrent Adjusted Ebitda Margin

1 Adjusted Ebitda: net income + income tax and social contribution + financial results + depreciation and amortization + impairment + non recurrent effects.

In addition, in 1Q26, Adjusted Ebitda was impacted negatively by the transmission segment, the effects of which were largely a combination of the following factors: (i) R$ 17 million decrease in the variation of the net result for construction costs and revenues; (ii) decrease of R$ 13 million O&M margin (O&M RAP, net of costs); mitigated by (iii) an increase of R$ 2 million due to the increase in remuneration from concession assets.

(in R$ million) 1Q26 1Q25 Chg. (%)

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:

Recurrent net income 792 826 4.1

(+) Income tax and social contribution 245 273 (10.3)

(+) Net financial result 827 623 32.7

Ebitda 2,248 2,044 10.0

(+) Depreciation and amortization 384 322 19.3

Non-recurrent effects

(+) Disposal of subsidiary (4) (4) -

Adjusted Ebitda 2,244 2,040 10.0

Statutory transmission Ebitda (IFRS) (321) (348) (7.8)

Regulatory transmission Ebitda (RAP) 200 168 19.0

Statutory quota holders Ebitda (IFRS) (224) (231) (3.0)

Regulatory quota holders Ebitda 190 175 8.6

Ebitda adjusted by transmission and quota effects 2,089 1,804 15.8

| Ebitda Change | R$ million

+10.0%

+15.8%

2,244

2,248

2,044

2,040

(34)

2,089

200

(10%)

133

(6%)

(4)

(56)

312

1,804

168

(9%)

167

(9%)

1,756

(84%)

1,790

(80%)

1,794

(80%)

1,529

(75%)

1,525

(75%)

1,469

(81%)

167

(8%)

348

(17%)

167

(8%)

348

(17%)

133

(6%)

321

(14%)

133

(6%)

321

(14%)

(180)

(25)

121

Ebitda 1Q25 Non-recurring

Adjusted

Ebitda 1Q25

IFRS*

adjustment

Ebitda adjusted by trans./quota 1Q25

Operating and commercial performance

Costs and Operating Expenses

Transmission Equity income

(TAG)

Ebitda adjusted by trans./quota 1Q26

IFRS*

adjustment

Adjusted Ebitda 1Q26

Non-recurring Ebitda 1Q26

Generation and trading1 Equity Income (TAG) Transmission

* IFRS: International Financial Reporting Standards.

1 Considering the result from generation and trading segments.

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